0000866829-12-000009.txt : 20120224 0000866829-12-000009.hdr.sgml : 20120224 20120224144747 ACCESSION NUMBER: 0000866829-12-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 19 CONFORMED PERIOD OF REPORT: 20111231 FILED AS OF DATE: 20120224 DATE AS OF CHANGE: 20120224 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HELIX ENERGY SOLUTIONS GROUP INC CENTRAL INDEX KEY: 0000866829 STANDARD INDUSTRIAL CLASSIFICATION: OIL, GAS FIELD SERVICES, NBC [1389] IRS NUMBER: 953409686 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-32936 FILM NUMBER: 12637330 BUSINESS ADDRESS: STREET 1: 400 N SAM HOUSTON PKWY E STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77060 BUSINESS PHONE: 2816180400 MAIL ADDRESS: STREET 1: 400 N SAM HOUSTON PKWY E STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77060 FORMER COMPANY: FORMER CONFORMED NAME: CAL DIVE INTERNATIONAL INC DATE OF NAME CHANGE: 19960821 10-K 1 helixfinal.htm HELIX ENERGY SOLUTIONS GROUP, INC. - 2011 FORM 10-K helixfinal.htm
 
 

 

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2011
or
   
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) of the Securities Exchange Act of 1934
 
 
For the transition period from                                                                      to
 
Commission File Number 001-32936
 
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
 
Minnesota
95-3409686
(State or other jurisdiction
of incorporation or organization)
(I.R.S. Employer
Identification No.)
   
400 North Sam Houston Parkway East Suite 400
77060
Houston, Texas
(Address of principal executive offices)
(Zip Code)
(281) 618-0400
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
Name of each exchange on which registered
Common Stock (no par value)
New York Stock Exchange
 
Securities registered Pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   þYes  oNo
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  oYes  þNo
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  þYes  oNo
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þYes  oNo
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of 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.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
   
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  oYes  þNo
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant based on the last reported sales price of the Registrant’s Common Stock on June 30, 2011 was approximately $1.6 billion.
 
The number of shares of the registrant’s Common Stock outstanding as of February 16, 2012 was 105,627,721.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 9, 2012, are incorporated by reference into Part III hereof.
 

 
 

 
 
 
   
Page
PART I
PART II
73
 
 
 
 
 
 
 
 
PART III
PART IV
 
 


Forward Looking Statements
 
This Annual Report on Form 10-K (“Annual Report”) contains various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. and represent our expectations and beliefs concerning future events.  This forward looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, included herein or incorporated herein by reference, that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements. Included in forward-looking statements are, among other things:    
 
 
statements regarding our business strategy, including the potential sale of assets and/or other investments in our subsidiaries and facilities, or any other business plans, forecasts or objectives, any or all of which is subject to change;
 
statements regarding our anticipated production volumes, results of exploration, exploitation, development, acquisition or  operations expenditures, and current or prospective reserve levels with respect to any oil and gas property or well;
 
statements related to commodity prices for oil and gas or with respect to the supply of and demand for oil and gas;
 
statements relating to our proposed acquisition, exploration, development and/or production of oil and gas properties, prospects or other interests and any anticipated costs related thereto;
 
statements related to environmental risks, exploration and development risks, or drilling and operating risks;
 
statements relating to the construction or acquisition of vessels or equipment and any anticipated costs related thereto;
 
statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items;
 
statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
 
statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
 
statements regarding the collectability of our trade receivables;
 
statements regarding anticipated developments, industry trends, performance or industry ranking;
 
statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business; 
 
statements related to our ability to retain key members of our senior management and key employees;
 
statements related to the underlying assumptions related to any projection or forward-looking statement; and
 
any other statements that relate to non-historical or future information.
 
Although we believe that the expectations reflected in these forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements.  These factors include, among other things:
 
 
impact of weak domestic and global economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;
 
uncertainties inherent in the development and production of oil and gas and in estimating reserves;
 
the geographic concentration of our oil and gas operations;
 
the effect of regulations on the offshore Gulf of Mexico oil and gas operations;
 
uncertainties regarding our ability to replace depletion;
 
unexpected future capital expenditures (including the amount and nature thereof);
 
impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;
 
 
 
 
 
 
 
the effects of indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt and could have other adverse consequences to us;
 
the effectiveness of our hedging activities;
 
the results of our continuing efforts to control costs and improve performance;
 
the success of our risk management activities;
 
the effects of competition;
 
the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations, and the terms of any such financing;
 
the impact of current and future laws and governmental regulations, including tax and accounting developments;
 
the effect of adverse weather conditions and/or other risks associated with marine operations, including the exposure of our oil and gas operations to tropical storm activity in the Gulf of Mexico;
 
the impact of operational disruptions affecting the Helix Producer I vessel which is crucial to producing oil and natural gas from our Phoenix field;
 
the effect of environmental liabilities that are not covered by an effective indemnity or insurance;
 
the potential impact of a loss of one or more key employees; and
 
the impact of general, market, industry or business conditions.
 
Our actual results could differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” beginning on page 18 of this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.
 
PART I
 
OVERVIEW
 
 Helix Energy Solutions Group, Inc. (together with its subsidiaries, unless context requires otherwise, “Helix,” “the Company,” “we,” “us” or “our”) is an international offshore energy company that provides field development solutions and other contracting services to the energy market as well as to our own oil and gas properties.  We have three reporting business segments: Contracting Services, Production Facilities, and Oil and Gas.  Our Contracting Services segment utilizes vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field.  These Contracting Services  operations are primarily located in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions.   Our Production Facilities segment consists of our ownership interest in certain production facilities in hub locations where there is potential for significant subsea tieback activity, our investment in a dynamically positioned floating production vessel (the “Helix Producer I” or “HP I”) and the recently established Helix Fast Action Response System (“HFRS” see “Our Strategy” below).  All of our Production Facilities activities are located in the Gulf of Mexico.  Our Oil and Gas segment engages in prospect generation, exploration, development and production activities all within in the Gulf of Mexico.
 
The future focus of the Company is on its Contracting Services businesses, including, well operations, robotics and subsea construction services.   For additional information regarding this strategy and about our contracting services operations, see sections titled “Our Strategy,” and “Contracting Services Operations” all included elsewhere within Item 1. “Business” of this Annual Report.
 
Our principal executive offices are located at 400 North Sam Houston Parkway East, Suite 400, Houston, Texas 77060; phone number 281-618-0400. Our common stock trades on the New York Stock Exchange (“NYSE”) under the ticker symbol “HLX”.  Our Chief Executive Officer submitted the annual CEO certification to the NYSE as required under its Listed Company Manual in May 2011. Our principal executive officer and our principal financial officer have made the certifications required under Section 302 of the Sarbanes-Oxley Act, which are included as exhibits to this Annual Report.
 
 
Please refer to the subsection “— Certain Definitions” on page 18 for definitions of additional terms commonly used in this Annual Report.  Unless otherwise indicated any reference to Notes herein refers to our Notes to the Consolidated Financial Statements located in Item 8. Financial Statements and Supplementary Data located elsewhere in this Annual Report.
 
BACKGROUND
 
Helix was incorporated in the state of Minnesota in 1979.  In July 2006, Helix acquired Remington Oil and Gas Corporation (“Remington”), an exploration, development and production company with operations located primarily in the Gulf of Mexico.   Until June 2009, Helix owned the majority of the common stock of a separate publicly-traded entity, Cal Dive International, Inc. (NYSE: DVR, and collectively with its subsidiaries referred to as “Cal Dive” or “CDI”), which performed shelf contracting services. Helix sold substantially all of its ownership interests in Cal Dive during 2009 and its remaining ownership interest in 2011 (see “Contracting Services Operations – Shelf Contracting” below and Note 3).  Prior to the divestiture of CDI, Shelf Contracting Services was our fourth reporting business segment.
 
OUR STRATEGY
 
Over the past three years, we have focused on improving our balance sheet by increasing our liquidity through dispositions of non-core business assets, decreasing our planned capital spending and reducing the amount of our debt outstanding.   Our focus is to shape the future direction of the Company around the Contracting Services business comprised of our well operations, robotics and subsea construction services.  We plan to supplement the expansion of our Contracting Services business with the cash generated by our production facilities business activities and the substantial cash flow associated with our oil and gas business.   We can generate cash from our oil and gas operations  through a combination of existing and/or future production from our properties and/or the sale of all or a portion of our oil and gas assets.
 
Since the beginning of 2009, we have generated approximately $600 million in pre-tax proceeds from dispositions of non-core business assets.  These transactions included approximately $55 million from the sale of individual oil and gas properties, over $500 million from the sale of our stockholdings in CDI and $25 million for the sale of our former reservoir consulting business.
 
 The primary goal of our Contracting Services business is to provide services and methodologies to the oil and natural gas industry which we believe are critical to developing offshore reservoirs and maximizing the economics from marginal fields. A secondary goal is for our oil and gas operations to generate prospects and to find and develop oil and gas employing our key services and methodologies resulting in a reduction in finding and development costs. Meeting these goals drives our ability to achieve our overall objective of maximizing the value for our shareholders. In order to achieve these goals we will:
 
Continue Expansion of Contracting Services Capabilities.  We will focus on providing offshore services that deliver the highest financial return to us.  We are planning to make strategic investments in capital projects that expand our service capabilities or add capacity to existing services in our key operating regions. We recently announced that we are initiating construction of a new multi-service semi-submersible well intervention and well operations vessel similar to our existing Q4000 vessel.   This vessel is expected to be completed and placed in service in 2015 at an approximate estimated cost of $525 million.   Our most recent completed capital investments include: upgrading the capabilities of our Q4000 vessel, converting a ferry vessel into a dynamically positioned floating production unit vessel (the HP I), and converting a former dynamically positioned cable lay vessel into a deepwater pipelay vessel (the Caesar).  We also completed the construction of the Well Enhancer that provides us with greater well intervention servicing capabilities, including installation of a coiled-tubing unit in 2010.
 
As recent evidence of our commitment to expand our contracting services capabilities we developed the HFRS.   The HFRS was developed as a culmination of our experience as a responder in the Gulf oil spill response and containment efforts in 2010.  The HFRS centers on two vessels, the HP I and the Q4000, both of which played a key role in Gulf oil spill response and containment efforts and are presently operating in the Gulf of Mexico.  In 2011, we signed an agreement with Clean Gulf Associates
 
 
5

 
     ("CGA"), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal
and state agencies and making the HFRS available for a two-year term to certain CGA participants who have executed utilization agreements with us. In addition to the agreement with CGA, we currently have signed separate utilization agreements with 24 of the CGA participant member companies specifying the day rates to be charged should the HFRS be deployed in connection with a well control incident.  The retainer fee for the HFRS became effective April 1, 2011.
 
Monetize Oil and Gas Reserves and Non-Core Assets.  As previously disclosed, we may pursue potential opportunities to sell all or a portion of our oil and gas assets.   Until such time as we dispose of our oil and gas assets, we will continue to pursue potential alternatives to sell or reduce our interests in oil and gas reserves once value has been created via prospect generation, discovery and/or development engineering.  We may sell interests in oil and gas reserves at any time during the life of the properties.
 
  Focus Exploration Drilling on Select Deepwater Prospects.   We are continuing to generate oil and gas prospects and expect to drill in areas we believe are likely to contain largely oil reserves, and where our contracting services assets may be utilized and incremental returns can be achieved through control of and application of our development services and methodologies. We plan to seek partners on these prospects to mitigate risk associated with the cost of drilling and development work.
 
  Continue Exploitation Activities and Converting PUD/PDNP Reserves into Production.  Over the years, our oil and gas operations have been able to achieve incremental operating returns and increased operating cash flow due in part to our ability to convert proved undeveloped reserves (“PUD”) and proved developed non-producing reserves (“PDNP”) into producing assets through successful exploitation drilling and well work. As of December 31, 2011, our PUD category represented approximately 16.1 MMBOE or 42% of our total estimated proved reserves.   We will focus on cost effectively developing these reserves to generate oil and gas production, or alternatively, selling full or partial interests in them to fund our core Contracting Services business and/or retire outstanding debt.
 
CONTRACTING SERVICES OPERATIONS
 
We provide offshore services and methodologies that we believe are critical to developing offshore reservoirs and maximizing production economics.  These “life of field” services are represented by four disciplines: (1) well operations, (2) robotics, (3) subsea construction and (4) production facilities.  We have disaggregated our contracting service operations into two reportable segments: Contracting Services and Production Facilities.  We provide a full range of contracting services primarily in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions primarily in deepwater. Our services include:
 
 
Development.  Installation of subsea pipelines, flowlines, control umbilicals, manifold assemblies and risers; pipelay and burial; installation and tie-in of riser and manifold assembly; commissioning, testing and inspection; and cable and umbilical lay and connection.  In 2011, we experienced increased demand for our services from the alternative energy industry.  Some of the services we provide to these alternative energy businesses include subsea power cable installation, trenching and burial, along with seabed coring and preparation for construction of windmill foundations.
 
 
Production.  Inspection, repair and maintenance of production structures, risers, pipelines and subsea equipment; well intervention; life of field support; and intervention engineering. 
 
 
Reclamation.  Reclamation and remediation services; plugging and abandonment services; platform salvage and removal services; pipeline abandonment services; and site inspections.
 
 
Production facilities. We are able to provide oil and natural gas processing services to oil and natural gas companies, primarily those operating in the deepwater of the Gulf of Mexico using our HP I vessel.  Currently, the HP I is being utilized to process production from our Phoenix field (Note 5).  In addition to the services provided by our HP I vessel, we maintain an equity investment in two production hub facilities in the Gulf of Mexico.  We also established the HFRS as a response resource in permit applications to federal and state agencies.


 
  As of December 31, 2011, our contracting services operations’ backlog supported by written agreements or contracts totaled $539.6 million, of which $505.0 million is expected to be performed in 2012.  At December 31, 2010, our backlog totaled $267.3 million.  These backlog contracts are cancellable without penalty in many cases.  Backlog is not a reliable indicator of total annual revenue for our contracting services operations as contracts may be added, cancelled and in many cases modified while in progress.
 
Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, spending for our contracting services fluctuates directly with the direction of oil and natural gas prices. However, some of our Contracting Services, generally our subsea construction activities, will often lag drilling operations by a period of 6 to 18 months, meaning that even if there were a sudden increase in deepwater permitting and subsequent drilling in the Gulf of Mexico, it probably would still be some time before we would start securing any awarded projects. The performance of our oil and gas operations is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors.
 
           Although we are still feeling the effects of the recent global recession and are experiencing the consequences of the additional regulatory requirements resulting from the Macondo well explosion and subsequent oil spill in the Gulf of Mexico in 2010, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long term increasing world demand for oil and natural gas emphasizes the need for continual replenishment of oil and gas production; (2) peaking global production rates; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing offshore activity, particularly in deepwater; and (6) increasing number of subsea developments. Our strategy of combining contracting services operations and oil and gas operations allows us to focus on trends (4) through (6) in that we pursue long-term sustainable growth by applying specialized subsea services to the broad external offshore market but with a complementary focus on marginal fields and new reservoirs in which we currently have an equity stake.
 
Well Operations
 
We engineer, manage and conduct well construction, intervention and asset retirement operations in water depths ranging from 200 to 10,000 feet. The increased number of subsea wells installed and the periodic shortfall in both rig availability and equipment have resulted in an increased demand for Well Operations services in the regions in which we operate.
 
As major and independent oil and gas companies expand operations in the deepwater basins of the world, development of these reserves will often require the installation of subsea trees. Historically, drilling rigs were typically necessary for subsea well operations to troubleshoot or enhance production, shift sleeves, log wells or perform recompletions. Three of our vessels serve as work platforms for well operations services at costs that are typically significantly less than offshore drilling rigs. In the Gulf of Mexico, our multi-service semi-submersible vessel, the Q4000, has set a series of well operations “firsts” in increasingly deeper water without the use of a traditional drilling rig.  In 2010, the Q4000 served as a key component in the Gulf well control and containment efforts.  The Q4000 serves an important role in the HFRS that was established in 2011 (see “Our Strategy” above).  In the North Sea, the Seawell has provided intervention and abandonment services for over 700 North Sea subsea wells since 1987. Competitive advantages of our vessels are derived from their lower operating costs, together with an ability to mobilize quickly and to maximize production time by performing a broad range of tasks related to intervention, construction, inspection, repair and maintenance. These services provide a cost advantage in the development and management of subsea reservoir developments. With the expected long-term increased demand for these services due to the growing number of subsea tree installations, we have the potential for significant backlog for well operations activities and, as a result, we constructed the Well Enhancer and it joined our fleet in October 2009 in the North Sea region.


     In February 2012, we announced that we are initiating construction of a new multi-service semi-submersible well intervention and well operations vessel similar to our existing Q4000 vessel.   This vessel is expected to be completed and placed in service in 2015 at an approximate estimated cost of $525 million.
 
The results of Well Operations are reported within our Contracting Services segment (Note 17).
 
Robotics
 
We have been actively engaged in Robotics for over 25 years.   We operate ROVs, trenchers and ROVDrills designed for offshore construction.  As marine construction support in the Gulf of Mexico and other areas of the world moves to deeper waters, use of ROV systems is increasing and the scope of their services is becoming more significant. Our vessels add value by supporting deployment of our ROVs. We provide our customers with vessel availability and schedule flexibility to meet the technological challenges of these subsea construction developments in the Gulf of Mexico and internationally. Our 41 ROVs and three trencher systems operate in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions.  We currently lease five vessels to support our Robotics services and we have historically engaged additional vessels on  short-term (spot) charters as needed.  In 2012, we expect to take possession of a new-build vessel, the Grand Canyon, that was commissioned specifically for our use under terms of a long-term charter agreement.  The Grand Canyon will initially be deployed to support  our new T1200 trencher system.
 
Over the past few years there has been a dramatic increase in offshore activity associated with the growing alternative energy industry.  Specifically there has been a large increase in the amount of services performed on behalf of the wind farm industry.   As the level of activity for offshore alternative energy projects has increased, so has the need for reliable services and related equipment.  Historically, this work was performed with the use of barges and other less suitable vessels but these types of services are now contracted to vessels such as our Deep Cygnus chartered vessel and the soon to be commissioned Grand Canyon chartered vessel that are more suitable for harsh weather conditions which can occur offshore, especially in the North Sea region where wind farming is presently concentrated.  In 2011, over 15% of our robotics revenues were related to alternative energy contracts.   Our robotics division is positioned to continue to increase the services it provides to the alternative energy business.   This increase is expected to include the use of our vessels as previously discussed, our trenchers (including the new T-1200 expected to be completed in 2012) that are used to bury the power generation lines and our ROV fleet used in both the installation process as well as ongoing maintenance of such offshore infrastructure.
 
The results of Robotics are reported within our Contracting Services segment (Note 17).
 
Subsea Construction
 
For over 30 years, we have supported offshore oil and natural gas infrastructure projects by providing our construction services.  Construction services which we believe are critical to the development of fields in the deepwater include the use of umbilical lay and pipelay vessels and ROVs.  We currently own three subsea umbilical lay and pipelay vessels. The Intrepid is a 381-foot DP-2 vessel capable of laying rigid and flexible pipe (up to 8 inches in diameter) and umbilicals. The Express is a 502-foot DP-2 vessel also capable of laying rigid and flexible pipe (up to 14 inches in diameter) and umbilicals. In January 2006, we acquired the Caesar, a mono-hull built in 2002 for the cable lay market. The Caesar is 485 feet long and is equipped with a DP-2 system.  The Caesar was placed in service in the Gulf of Mexico in May 2010 following its conversion into a subsea pipelay asset capable of laying rigid pipe up to 30 inches in diameter.
 
The results of our Subsea Construction operations are reported within our Contracting Services segment (Note 17).


 
Production Facilities
 
We own interests in two production facilities in hub locations where there is potential for subsea tieback activity. There are a significant number of small discoveries that cannot justify the economics of a dedicated host facility. These discoveries are typically developed as subsea tie backs to existing facilities when capacity through the facility is available. We have invested in two over-sized facilities that allow the operators of these fields to tie back without burdening the operator of the hub reservoir. We are positioned to facilitate the tie back of certain of these smaller reservoirs to these hubs through our Contracting Services operations.  Ownership of production facilities enables us to earn a transmission company type return through tariff charges while periodically providing construction work for our vessels. We own a 50% interest in Deepwater Gateway, which owns the Marco Polo TLP located in 4,300 feet of water in the Gulf of Mexico. We also own a 20% interest in Independence Hub which owns the Independence Hub platform, a 105-foot deep draft, semi-submersible platform located in a water depth of 8,000 feet that serves as a regional hub for up to one billion cubic feet (“Bcf”) of natural gas production per day from multiple ultra-deepwater fields in the eastern Gulf of Mexico.
 
We also seek to employ oil and gas processing alternatives that permit the development of some fields that otherwise would be non-commercial to develop.  For example, through an approximate 81% owned and consolidated entity, we completed the conversion of a vessel (the HP I) into a ship-shaped dynamically positioning floating production unit capable of processing up to 45,000 barrels of oil and 80 MMcf of natural gas per day.  The HP I is currently being used to process production from our Phoenix field, which we acquired in 2006 after the hurricanes of 2005 destroyed the TLP which was being used to produce the field.  Once production in the Phoenix field ceases to be economic, this re-deployable facility is expected to move to a new location as contracted by a third party, or by our direction to be used to produce other internally-owned reservoirs.
 
As noted in “Our Strategy” above, we established the HFRS in 2011.  The HFRS was contracted to certain members of CGA, a consortium of oil and gas industry participants in the Gulf of Mexico, who have executed a utilization agreement with us.  CGA pays us a fixed retainer fee for our vessels, the Q4000 and HP I,  both of which are currently operating in the Gulf of Mexico, to be named as well control  resources in filed response plans filed with federal and state authorities.  This retainer fee is a component of our Production Facilities business segment.
 
The results of production facilities services are reported as our Production Facilities segment (Note 17).
 
Shelf Contracting
 
Our former Shelf Contracting segment represented the operations and results of CDI while CDI was a consolidated, majority-owned subsidiary of Helix.   We deconsolidated CDI on June 10, 2009 when our ownership interest in CDI decreased below 50% (Note 3).  In 2011, we sold our remaining ownership interest in CDI.  Shelf Contracting services provided by CDI included manned diving services, pipelay and pipebury services, platform installation and salvage service.  Shelf Contracting also performed saturation, surface and mixed gas diving which enabled us to provide a full complement of manned diving services in water depths of up to 1,000 feet.  For the results of our former Shelf Contracting services segment see Note 17.
 
 OIL & GAS OPERATIONS
 
In 1992, we formed our oil and gas business unit to achieve incremental returns, to expand the utilization of our contracting services assets, and to develop and provide more efficient solutions for offshore abandonment requirements.  We have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be explored and developed.  We have assembled services that allow us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.  At December 31, 2011, our estimated proved reserves totaled approximately 38.9 MMBOE, all of which are associated with properties located in the Gulf of Mexico.
           
 
    As we previously indicated, under certain circumstances we might consider strategic sales of some  or all of our oil and gas properties.  As evidence of this strategy, in December 2011 we sold our ownership interest in Green Canyon Block 490 for gross proceeds of approximately $31 million.  The transaction is also subject to certain customary closing conditions, which will result in the receipt of additional proceeds for capital expenditures we paid subsequent to the sale transaction effective date.   In January 2012, we sold our oil and gas properties within the Main Pass area of the Gulf of Mexico.  These seven Main Pass properties were all operated by third parties and the acquirer obtained our ownership interests by assuming our pro rata share of each field’s asset retirement obligation.  See Note 5 for additional information regarding our recent sale of oil and gas properties.  We believe that owning interests in oil and gas reservoirs, particularly in the deepwater, provides the following:
 
 
a potential backlog for our contracting service assets as a hedge against cyclical service asset utilization;
 
potential utilization for new non-conventional applications of contracting service assets to hedge against lack of initial market acceptance and utilization risk; and
 
incremental returns.
 
Our oil and gas operations are currently involved in all stages of a reservoir’s life. This complete life-cycle involvement allows us to potentially improve the economics of a reservoir that might otherwise be considered non-commercial or non-impact and has identified us as a value adding partner to many producers. Our expertise, along with similarly aligned interests, allows us to develop more efficient relationships with other producers. With a historical focus on acquiring non-impact reservoirs or mature fields, we have been successful in acquiring equity interests in several undeveloped reservoirs in the Deepwater. In the event we continue to own and operate our oil and gas assets, developing these fields over the next few years will require significant capital commitments by us and/or others.
 
Our oil and gas operations have a prospect inventory, mostly in the Deepwater, which we believe may generate additional life of field services for our Contracting Services vessels. Our Oil and Gas segment has a proven track record of developing prospects into production in the U.S. Gulf of Mexico.  We plan to seek partners on these prospects to mitigate risk associated with the costs of drilling and development.
 
We identify prospective oil and gas properties primarily by using 3-D seismic technology. After acquiring an interest in a prospective property, our strategy is to partner with others to drill one or more exploratory wells. If the exploratory well(s) find commercial oil and/or gas reserves, we complete the well(s) and install the necessary infrastructure to begin producing the oil and/or gas. Because our operations are located in the Gulf of Mexico, we must install facilities such as offshore platforms and gathering pipelines in order to produce the oil and gas and deliver it to the marketplace. Certain properties require additional drilling to fully develop the oil and gas reserves and maximize the production from a particular discovery.
 
Our oil and gas operations include an experienced team of personnel providing services in geology, geophysics, reservoir engineering, drilling, production engineering, facilities management, lease operations and petroleum land management. We seek to maximize profitability by lowering finding and development costs, lowering development time and cost, operating the field more effectively, and extending the reservoir life through well exploitation operations. When a company sells a property on the Outer Continental Shelf (“OCS”), it retains the financial responsibility for the asset retirement obligations if its purchaser becomes financially unable to do so. Thus, it becomes important that a property be sold to a purchaser that has the financial wherewithal to perform its plug and abandonment obligations. We believe we have a strong reputation among major and independent oil companies. In addition, our reservoir engineering and geophysical expertise, along with our access to contracting service assets that can positively impact development costs, have enabled us to partner with many other oil and gas companies in offshore development projects. We share ownership in our oil and gas properties with various industry participants. We currently operate the majority of our offshore properties. An operator is generally able to maintain a greater degree of control over the timing and amount of capital expenditures than a non-operating interest owner. See Item 2. Properties “— Summary of Oil and Natural Gas Reserve Data” for detailed disclosures of our oil and gas properties.
 
The results of our oil and gas operations are reported within our Oil and Gas segment (Note 17).
 
 
GEOGRAPHIC AREAS
 
Revenue by individually significant country is as follows (in thousands):
 
     
Year Ended December 31,
 
     
2011
     
2010
     
2009
 
                         
United States
 
$
1,013,476
   
$
827,597
   
$
923,481
 
United Kingdom
   
275,499
     
198,011
     
124,896
 
India
   
44,772
     
56,311
     
233,466
 
Other
   
64,860
     
117,919
     
179,844
 
     Total
 
$
1,398,607
   
$
1,199,838
   
$
1,461,687
 
                         
We include the property and equipment, net of accumulated depreciation, in the geographic region in which it is legally owned.  The following table provides our property and equipment, net of depreciation, by individually significant country (in thousands):
 
     
Year Ended December 31,
 
     
2011
     
2010
     
2009
 
                         
United States
 
$
2,034,978
   
$
2,236,455
   
$
2,564,673
 
United Kingdom
   
281,430
     
275,012
     
284,637
 
Other
   
14,919
     
15,613
     
14,396
 
     Total
 
$
2,331,327
   
$
2,527,080
   
$
2,863,706
 
 
CUSTOMERS
 
Our customers include major and independent oil and gas producers and suppliers, pipeline transmission companies and offshore engineering and construction firms. The level of services required by any particular contracting customer depends on the size of that customer’s capital expenditure budget in a particular year. Consequently, customers that account for a significant portion of contract revenues in one fiscal year may represent an immaterial portion of contract revenues in subsequent fiscal years. The percent of consolidated revenue from major customers, those whose total represented 10% or more of our consolidated revenues, was as follows: 2011— Shell (49%); 2010 — Shell (29%) and BP Plc (17%) and 2009—Shell (19%). These customers were primarily purchasers of our oil and natural gas production. We estimate that in 2011 we provided subsea services to over 75 customers.
 
Our contracting services projects were historically of short duration and generally were awarded shortly before mobilization.  However, since 2007, we have entered into many longer term contracts for certain of our subsea construction, well operations and production facilities vessels.  In addition, our production portfolio inherently provides a backlog of work for our services that we can complete at our option based on market conditions.  As of December 31, 2011, our contracting services operations’ backlog supported by written agreements or contracts totaled $539.6 million, of which $505.0 million is expected to be performed in 2012.  These backlog contracts are cancellable without penalty in many cases.  Backlog is not a reliable indicator of total annual revenue for our Contracting Services businesses as contracts may be added, cancelled and in many cases modified while in progress.


 
COMPETITION
 
The contracting services industry is highly competitive. While price is a factor, the ability to acquire specialized vessels, attract and retain skilled personnel, and demonstrate a good safety record are also important. Our principal competitors include Oceaneering International, Inc., Saipem,  Allseas Group S.A., Subsea 7 S.A.,  Technip and McDermott International, Inc.  Our competitors in the well operations business are the international drilling contractors and specialized contractors.
 
Our oil and gas operations compete with large integrated oil and gas companies as well as independent exploration and production companies for offshore leases on properties. We also encounter significant competition for the acquisition of mature oil and gas properties. If we continue to own our oil and gas business, our potential ability to acquire additional future properties will depend upon our ability to evaluate and select suitable properties and consummate transactions in a historically highly competitive environment. Many of our competitors may have significantly more financial, personnel, technological, and other resources available to them. In addition, some of the larger integrated companies may be better able to respond to industry changes including price fluctuation, oil and natural gas demand, and governmental regulations. Small or mid-sized producers, and in some cases financial players, with a focus on acquisition of proved developed and undeveloped reserves, are often competition for development properties.
 
TRAINING, SAFETY AND QUALITY ASSURANCE
 
We have established a corporate culture in which QHSE remains among the highest of priorities. Our corporate goal, based on the belief that all accidents can be prevented, is to provide an incident-free workplace by focusing on correct and safe behavior. Our QHSE procedures, training programs and management system were developed by management personnel, common industry work practices and by employees with on-site experience who understand the physical challenges of the ocean work site. As a result, management believes that our QHSE programs are among the best in the industry. We maintain a company-wide effort to enhance and provide continuous improvements to our behavioral based safety process, as well as our training programs, that continue to focus on safety through open communication. The process includes the documentation of all daily observations, collection of data and data treatment to provide the mechanism of understanding both safe and unsafe behaviors at the worksite. In addition, we initiated scheduled hazard hunts by project management on each vessel, complete with assigned responsibilities and action due dates.  Our Contracting Services business has been independently certified compliant in ISO 9001 (Quality Management Systems) and ISO 14001 (Environmental Management System).
 
GOVERNMENT REGULATION
 
Many aspects of the offshore marine construction industry are subject to extensive governmental regulations. We are subject to the jurisdiction of the U.S. Coast Guard (“Coast Guard”), the U.S. Environmental Protection Agency (“EPA”), three divisions of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (“BOEM”), the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Office of Natural Resource Revenue (“ONRR”) and U.S. Customs Service, as well as private industry organizations such as the American Bureau of Shipping (“ABS”).  The BOEM and BSEE formally comprised the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) until October 2011.  Prior to June 2010 the BOEMRE was known as the Minerals Management Service (“MMS”).  In the North Sea, international regulations govern working hours and a specified working environment, as well as standards for diving procedures, equipment and diver health. These North Sea standards are some of the most stringent worldwide. In the absence of any specific regulation, our North Sea operations adhere to standards set by the International Marine Contractors Association and the International Maritime Organization. In addition, we operate in other foreign jurisdictions that have various types of governmental laws and regulations to which we are subject.
 
The Coast Guard sets safety standards and is authorized to investigate vessel and diving accidents and to recommend improved safety standards. The Coast Guard also is authorized to inspect vessels at will. We are required by various governmental and quasi-governmental agencies to obtain
 
 
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various permits, licenses and certificates with respect to our operations. We believe that we have obtained or can obtain all permits, licenses and certificates necessary for the conduct of our business.
 
In addition, we depend on the demand for our services from the oil and gas industry, and therefore, our business is affected by laws and regulations, as well as changing tax laws and policies, relating to the oil and gas industry generally. In particular, the development and operation of oil and gas properties located on the OCS of the United States is regulated primarily by the BOEM.
 
The BOEM requires lessees of OCS properties to post bonds or provide other adequate financial assurance in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators on the OCS are currently required to post an area-wide bond of $3.0 million, or $0.5 million per producing lease. We have provided adequate financial assurance for our offshore leases as required by the BOEM.
 
We acquire production rights to offshore mature oil and gas properties under federal oil and gas leases, which the BOEM and BSEE administers. These leases contain relatively standardized terms and require compliance with detailed BOEM and BSEE regulations and orders pursuant to the Outer Continental Shelf Lands Act (“OCSLA”). These BOEM and BSEE directives are subject to change. The BOEM and BSEE have promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The BOEM and BSEE also has issued regulations restricting the flaring or venting of natural gas and prohibiting the burning of liquid hydrocarbons without prior authorization. Similarly, the BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. Finally, under certain circumstances, the BOEM and BSEE may require any operations on federal leases to be suspended or terminated or may expel unsafe operators from existing OCS platforms and bar them from obtaining future leases. Suspension or termination of our operations or expulsion from operating on our leases and obtaining future leases could have a material adverse effect on our financial condition and results of operations.
 
In April 2010, the Deepwater Horizon drilling rig experienced an explosion and fire, and later sank into the Gulf of Mexico.  The complete destruction of the Deepwater Horizon rig also resulted in a significant release of crude oil into the Gulf.  As a result of this explosion and oil spill, a moratorium was placed on offshore deepwater drilling in the United States, which was subsequently lifted on October 12, 2010 and replaced with enhanced safety standards for offshore deepwater drilling.  Under the enhanced safety standards, in order for an operator to resume deepwater drilling, it is required to comply with existing and newly developed regulations and standards, including Notice to Lessees (NTL), 2010-N05 (Safety NTL), NTL 2010-N06 (Environmental NTL) and the Interim Final Rule (Drilling Safety Rule), and NTL 2010-N10 (Compliance and Evaluation NTL).  Inspections will be conducted of each deepwater drilling operation for compliance with BOEM and BSEE regulations, including but not limited to the testing of blow out preventers, before drilling resumes. As companies resume operations, they will also need to comply with the Safety and Environmental Management System (SEMS Rule) within the deadlines specified by the regulation.  Additionally, each operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout, regardless of the company or operator involved.  During 2011, the Department of the Interior  established a mechanism relating to the availability of blowout containment resources, including our HFRS system, and these resources are now being regulated by the BOEM and BSEE.  It is also expected that the BOEM and BSEE will issue further regulations regarding deepwater offshore drilling.
 
Under the OCSLA and the Federal Oil and Gas Royalty Management Act, the ONRR establishes regulations that set the basis for royalties on oil and gas. The regulations address the proper way to value production for royalty purposes, including the deductibility of certain post-production costs from that value. Separate sets of regulations govern natural gas and oil and are subject to periodic revision by the ONRR.
 
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (“NGPA”), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”). In the past, the federal government has regulated the prices at which oil and gas could be sold. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the
 
 
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Natural Gas Wellhead Decontrol Act was enacted, removing both price and non-price controls from natural gas sold in “first sales” no later than January 1, 1993.  While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future.
 
Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and FERC since 1985 that affect the economics of natural gas production, transportation and sales. In addition, as a result of the Energy Policy Act of 2005, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC jurisdiction. In addition, however, changes in FERC rules and regulations may also affect the intrastate transportation of natural gas, as well as the sale of natural gas in interstate and intrastate commerce, under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and to prevent fraud and manipulation of interstate transportation markets. We cannot predict what further action FERC will take on these matters, but we do not believe any such action will materially adversely affect us differently from other companies with which we compete.
 
Additional proposals and proceedings before various federal and state regulatory agencies and the courts could affect the oil and gas industry. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by FERC will continue indefinitely.
 
ENVIRONMENTAL REGULATION
 
Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials (including oil) into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed. Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.
 
The Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements on “Responsible Parties” related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A “Responsible Party” includes the owner or operator of an onshore facility, a vessel or a pipeline, and the lessee or permittee of the area in which an offshore facility is located. OPA imposes liability on each Responsible Party for oil spill removal costs and for other public and private damages from oil spills. Failure to comply with OPA may result in the assessment of civil and criminal penalties. OPA establishes liability limits of $350 million for onshore facilities, all removal costs plus $75 million for offshore facilities, and the greater of $854,400 or $1,000 per gross ton for vessels other than tank vessels. The liability limits are not applicable, however, if the spill is caused by gross negligence or willful misconduct; if the spill results from violation of a federal safety, construction, or operating regulation; or if a party fails to report a spill or fails to cooperate fully in the cleanup. Few defenses exist to the liability imposed under OPA. Management is currently unaware of any oil spills for which we have been designated as a Responsible Party under OPA that will have a material adverse impact on us or our operations.
 
OPA also imposes ongoing requirements on a Responsible Party, including preparation of an oil spill contingency plan and maintaining proof of financial responsibility to cover a majority of the costs in a potential spill. We believe that we have appropriate spill contingency plans in place. With respect to financial responsibility, OPA requires the Responsible Party for certain offshore facilities to demonstrate financial responsibility of not less than $35 million, with the financial responsibility requirement potentially increasing up to $150 million if the risk posed by the quantity or quality of oil that is explored for or produced indicates that a greater amount is required. The BOEM has promulgated regulations implementing these financial responsibility requirements for covered offshore facilities. Under the BOEM
 
 
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regulations, the amount of financial responsibility required for an offshore facility is increased above the minimum amounts if the “worst case” oil spill volume calculated for the facility exceeds certain limits established in the regulations. We believe that we currently have established adequate proof of financial responsibility for our onshore and offshore facilities and that we satisfy the BOEM requirements for financial responsibility under OPA and applicable regulations.
 
In addition, OPA requires owners and operators of vessels over 300 gross tons to provide the Coast Guard with evidence of financial responsibility to cover the cost of cleaning up oil spills from such vessels. We currently own and operate seven vessels over 300 gross tons. We have provided satisfactory evidence of financial responsibility to the Coast Guard for all of our vessels.
 
The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the United States and imposes potential liability for the costs of remediating releases of petroleum and other substances. The controls and restrictions imposed under the Clean Water Act have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System Program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the exploration for, and production of, oil and gas into certain coastal and offshore waters. The Clean Water Act provides for civil, criminal and administrative penalties for any unauthorized discharge of oil and other hazardous substances and imposes liability on responsible parties for the costs of cleaning up any environmental contamination caused by the release of a hazardous substance and for natural resource damages resulting from the release. Many states have laws that are analogous to the Clean Water Act and also require remediation of releases of petroleum and other hazardous substances in state waters. Our vessels routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. Our vessels transport bulk chemical materials used in drilling activities and also transport liquid mud which contains oil and oil by-products. Offshore facilities and vessels operated by us have facility and vessel response plans to deal with potential spills. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
 
OCSLA provides the federal government with broad discretion in regulating the production of offshore resources of oil and gas, including authority to impose safety and environmental protection requirements applicable to lessees and permittees operating in the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancellation of leases. Because our operations rely on offshore oil and gas exploration and production, if the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases, such action could have a material adverse effect on our financial condition and results of operations. As of this date, we believe we are not the subject of any civil or criminal enforcement actions under OCSLA.
 
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) contains provisions requiring the remediation of releases of hazardous substances into the environment and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons including owners and operators of contaminated sites where the release occurred and those companies who transport, dispose of, or arrange for disposal of hazardous substances released at the sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Third parties may also file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although we handle hazardous substances in the ordinary course of business, we are not aware of any hazardous substance contamination for which we may be liable.
 
We operate in foreign jurisdictions that have various types of governmental laws and regulations relating to the discharge of oil or hazardous substances and the protection of the environment. Pursuant to these laws and regulations, we could be held liable for remediation of some types of pollution, including the release of oil, hazardous substances and debris from production, refining or industrial facilities, as
 
 
15

 
well as other assets we own or operate or which are owned or operated by either our customers or our sub-contractors.
 
A variety of regulatory developments, proposals or requirements and legislative initiatives have been introduced in the domestic and international regions in which we operate that are focused on restricting the emissions of carbon dioxide, methane and other greenhouse gases.  For example, the U.S. Congress has from time to time considered legislation to reduce greenhouse gas emissions, and almost one-half of the states already have taken legal measures to reduce greenhouse gas emissions, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.
 
In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an “air pollutant” under the Federal Clean Air Act and thus subject to future regulation.   In December 2009, the EPA issued an  “endangerment and cause or contribute finding” for greenhouse gases under the Federal Clean Air Act, which allowed the EPA to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Since 2009, the EPA has issued regulations that, among other things, require a reduction in emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources.
 
Additionally, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring in 2010.  On November 9, 2010, the EPA expanded its greenhouse reporting rule to include onshore petroleum and natural gas production, offshore petroleum and natural gas production, onshore natural gas processing, natural gas transmission, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export, and natural gas distribution facilities. Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis, with reporting beginning in 2012 for emissions in 2011.
 
Management believes that we are in compliance in all material respects with the applicable environmental laws and regulations to which we are subject. We do not anticipate that compliance with existing environmental laws and regulations will have a material effect upon our capital expenditures, earnings or competitive position. However, changes in the environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future.
 
INSURANCE MATTERS
 
The well operations, robotics and subsea construction activities constituting our Contracting Services business involve a high degree of operational risk.  Hazards, such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in marine operations.  These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations.  Damages arising from such occurrences may result in lawsuits asserting large claims.  Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject.  A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow.
 
Similarly, our oil and gas operations are subject to risks incident to the operation of oil and gas wells, including but not limited to uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. Although we maintain insurance against some of these risks we cannot insure against all possible losses.  As a result, any damage or loss not covered by our insurance could have a material adverse effect on our financial condition, results of operations and cash flow.
 

 
As discussed above, we maintain insurance policies to cover some of our risk of loss associated with our operations.   We maintain the amount of insurance we believe is prudent based on our estimated loss potential.  However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).
 
Our energy and marine insurance is renewed annually on July 1152ber 72005 Plan - Lovoi-12-0 and covers a twelve-month period from July 1 to June 30.
 
For our contracting services business we maintain Hull and Increased Value insurance, which provides coverage for physical damage up to an agreed amount for each vessel. The deductibles are $1.0 million on the Q4000, HP I and Well Enhancer, $500,000 on the Intrepid, Seawell and Express, and $375,000 on the Caesar.  In addition to the primary deductibles, the vessels are subject to an annual aggregate deductible of $1.75 million.  We also carry Protection and Indemnity (“P&I”) insurance which covers liabilities arising from the operation of the vessels and General Liability insurance which covers liabilities arising from construction operations. The deductible on both the P&I and General Liability is $100,000 per occurrence. Onshore employees are covered by Workers’ Compensation.  Offshore employees and marine crews are covered by our Maritime Employers Liability insurance policy which covers Jones Act exposures and includes a deductible of $100,000 per occurrence plus a $1.0 million annual aggregate deductible. In addition to the liability policies described above, we currently carry various layers of Umbrella Liability for total limits of $500 million in excess of primary limits. Our self-insured retention on our medical and health benefits program for employees is $250,000 per participant.
 
 We also maintain Operator Extra Expense coverage that provides up to $150 million of coverage per each loss occurrence for a well control issue.   Separately, we also maintain $500 million of liability insurance and $150 million of oil pollution insurance.   For any given oil spill event we have up to $650 million of insurance coverage.   We have not insured for windstorm damage under traditional insurance policies for the past three years because premium and deductibles would be relatively substantial for the coverage provided. In order to mitigate potential loss with respect to our most significant oil and gas properties from hurricanes in the Gulf of Mexico, we purchased Catastrophic Bond instruments covering each of the last three insurance years, with the most recent instrument covering the period from July 1, 2011 through June 30, 2012.   Our current Catastrophic Bond provides for payments of negotiated amounts should the eye of a Category 2 or Category 3 or greater hurricane pass within specific pre-defined areas encompassing our more significant oil and gas producing fields.
 
We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel.   Under these agreements we are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel.  With respect to well work by our contracting services operations, the customer is generally contractually responsible for pollution emanating from the well.  We separately maintain additional coverage for an amount up to $100 million that would cover us under certain circumstances against any such third party claims associated with well control events.
 
EMPLOYEES
 
 As of December 31, 2011, we had 1,655 employees, approximately 675 of which were salaried personnel.  As of December 31, 2011, we also contracted with third parties to utilize 140 non-U.S. citizens to crew our foreign flagged vessels.  Except for a very limited number of our workshop employees in Australia, our employees do not belong to a union nor are they employed pursuant to any collective bargaining agreement or any similar arrangement. We believe our relationship with our employees and foreign crew members is favorable.


 
WEBSITE AND OTHER AVAILABLE INFORMATION
 
We maintain a website on the Internet with the address of www.HelixESG.com. Copies of this Annual Report for the year ended December 31, 2011, and previous and subsequent copies of our Quarterly Reports on Form 10-Q and any Current Reports on Form 8-K, and any amendments thereto, are or will be available free of charge at such website as soon as reasonably practicable after they are filed with, or furnished to, the Securities and Exchange Commission (“SEC”).  In addition, the Investor Relations portion of our website contains copies of our Code of Conduct and Business Ethics and our Code of Ethics for Chief Executive Officer and Senior Financial Officers. We make our website content available for informational purposes only. Information contained on our website is not part of this report and should not be relied upon for investment purposes. Please note that prior to March 6, 2006, the name of the Company was Cal Dive International, Inc.
 
The general public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us. The Internet address of the SEC’s website is www.sec.gov.
 
We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Conduct and Business Ethics and our Code of Ethics for Chief Executive Officer and Senior Financial Officers and any waiver from any provision of those codes by posting such information in the Investor Relations section of our website at www.HelixESG.com.
 
CERTAIN DEFINITIONS
 
Defined below are certain terms helpful to understanding our business that are located through this Annual Report:
 
Bcfe:  One billion cubic feet equivalent, with one barrel of oil being equivalent to six thousand cubic feet of natural gas.
 
BOE:  One barrel of oil equivalent, with each six thousand cubic feet of natural gas equivalent to one barrel of oil.   Common references in this Annual Report include MBOE, which refers to a thousand barrels of oil equivalent and MMBOE, which refers to a million barrels of oil equivalent.
 
BOEMRE:  Until October 1, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement, an agency of the Department of Interior, had responsibility for all aspects of offshore federal leasing, including for overseeing the development of energy and mineral resources on the Outer Continental Shelf of the Gulf of Mexico.   The multi-departmental BOEMRE was the successor to the Mineral Management Service (“MMS”), which until June 2010 was the federal regulatory body overseeing the development of mineral resources in the United States.  Effective October 1, 2011, the BOEMRE was separated into two separate federal agencies, the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Management (“BSEE”).
 
BOEM:  As noted above,  the BOEM is one of two successor federal agencies to BOEMRE.   The BOEM, is responsible for managing environmentally and economically responsible development of the U.S. offshore resources.  Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies.
 
BSEE:  The BSEE is the second of the two successor federal agencies to BOEMRE. The BSEE is responsible for safety and environmental oversight of offshore oil and gas operations, including permitting and inspections, of offshore oil and gas operations.  Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development
 
 
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and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs.
 
Deepwater:  Water depths exceeding 1,000 feet.
 
Dynamic Positioning (DP):  Computer directed thruster systems that use satellite based positioning and other positioning technologies to ensure the proper counteraction to wind, current and wave forces enabling the vessel to maintain its position without the use of anchors.
 
DP-2:  Two DP systems on a single vessel providing the redundancy which allows the vessel to maintain position even with the failure of one DP system, required for vessels which support both manned diving and robotics and for those working in close proximity to platforms. DP-2 is necessary to provide the redundancy required to support safe deployment of divers, while only a single DP system is necessary to support ROV operations.
 
E&P:  Oil and gas exploration and production activities.
 
F&D:  Total cost of finding and developing oil and gas reserves.
 
G&G:  Geological and geophysical.
 
IRM:  Inspection, repair and maintenance.
 
Life of Field Services:  Services performed on offshore facilities, trees and pipelines from the beginning to the end of the economic life of an oil field, including installation, inspection, maintenance, repair, well intervention and abandonment.
 
MBbl:  When describing oil or other natural gas liquid, refers to 1,000 barrels with each barrel containing 42 gallons.
 
MMBbl: When describing oil or other natural gas liquid, refers to millions of barrels.
 
Mcf:  When describing natural gas, refers to 1 thousand cubic feet.
 
MMcf:  When describing natural gas, refers to 1 million cubic feet.
 
Outer Continental Shelf (OCS):  For purposes of our industry, areas in the Gulf of Mexico from the shore to 1,000 feet of water depth.
 
Peer Group-Contracting Services:  For purposes of this Annual Report on Form 10-K, FMC Technologies, Inc. (NYSE: FTI), Atwood Oceanics, Inc. (NYSE: ATW), McDermott International, Inc. (NYSE: MDR), Oceaneering International, Inc. (NYSE: OII), Cameron International Corporation (NYSE: CAM), Oil States International, Inc. (NYSE: OIS), Rowan Companies, Inc. (NYSE: RDC), Superior Energy Services, Inc (NYSE: SPN), Tetra Technologies, Inc. (NYSE: TTI), Petrofac (LSE:PFC.L) and Dril-Quip, Inc. (NYSE:DRQ).
 
Peer Group-Oil and Gas:  For purposes of this Annual Report, ATP Oil & Gas Corporation (NASDAQ: ATPG), W&T Offshore, Inc. (NYSE: WTI), Energy XXI (Bermuda) Limited (NYSE: EXXI), and Stone Energy Corporation (NYSE: SGY).
 
Proved Developed Non-Producing (PDNP):   Proved developed oil and gas reserves that are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, or (2) wells that require additional completion work or future recompletion prior to the start of production.
 
Proved Developed Shut-In (PDSI):  Proved developed oil and gas reserves associated with wells that exhibited calendar year production, but were not online January 1, 2012.    
 
 
 
Proved Developed Reserves (PDP):  Reserves that geological and engineering data indicate with reasonable certainty to be recoverable today, or in the near future, with current technology and under current economic conditions.
 
Proved Undeveloped Reserves (PUD):  Proved undeveloped oil and gas reserves that are expected to be recovered from a new well on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
QHSE:  Quality, Health, Safety and  Environmental programs to protect the environment, safeguard employee health and avoid injuries.
 
Remotely Operated Vehicle (ROV):  Robotic vehicles used to complement, support and increase the efficiency of diving and subsea operations and for tasks beyond the capability of manned diving operations.
 
ROVDrill:  ROV deployed coring system developed to take advantage of existing ROV technology. The coring package, deployed with the ROV system, is capable of taking cores from the seafloor in water depths up to 3,000 meters. Because the system operates from the seafloor there is no need for surface drilling strings and the larger support spreads required for conventional coring.
 
Saturation Diving:  Saturation diving, required for work in water depths between 200 and 1,000 feet, involves divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site.
 
Spar:  Floating production facility anchored to the sea bed with catenary mooring lines.
 
Spot Market:  Prevalent market for subsea contracting in the Gulf of Mexico, characterized by projects that are generally short in duration and often on a turnkey basis. These projects often require constant rescheduling and the availability or interchangeability of multiple vessels.
 
Subsea Construction Vessels:  Subsea services are typically performed with the use of specialized construction vessels which provide an above-water platform that functions as an operational base for divers and ROVs. Distinguishing characteristics of subsea construction vessels include DP systems, saturation diving capabilities, deck space, deck load, craneage and moonpool launching. Deck space, deck load and craneage are important features of a vessel’s ability to transport and fabricate hardware, supplies and equipment necessary to complete subsea projects.
 
Tension Leg Platform (TLP):  A floating production facility anchored to the seabed with tendons.
 
Trencher or Trencher System:  A subsea robotics system capable of providing post lay trenching, inspection and burial (PLIB) and maintenance of submarine cables and flowlines in water depths of 30 to 7,200 feet across a range of seabed and environmental conditions.
 
Well Operations Services:  Activities related to well maintenance and production management/enhancement services. Our well intervention operations include the utilization of slickline and electric line services, pumping services, specialized tooling and coiled tubing services.
 
Working Interest:  The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.


 
 
Shareholders should carefully consider the following risk factors in addition to the other information contained herein. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Annual Report could have a material adverse effect on our business, results of operations and financial position.
 
Risks Relating to General Corporate Matters
 
Business Risks
 
Our results of operations could be adversely affected if our business assumptions do not prove to be accurate or if adverse changes occur in our business environment, including the following areas:
 
 
 
general global economic and business conditions, which affect demand for oil and natural gas and, in turn, our business;
 
 
 
our ability to manage risks related to our business and operations;
 
 
 
our ability to compete against companies that provide more services and products than we do, including “integrated service companies”;
 
 
 
our ability to attract and retain skilled, trained personnel to provide technical services and support for our business;
 
 
 
our ability to procure sufficient supplies of materials essential to our business  in periods of high demand, and to reduce our commitments for such materials in periods of low demand;
  
 
 
consolidation by our customers, which could result in loss of a customer; and
 
 
 
changes in laws or regulations, including laws relating to the environment or to the oil and gas industry in general, and other factors, many of which are beyond our control.
 
  The Deepwater Horizon drilling rig explosion in the Gulf of Mexico, the subsequent oil spill and the resulting enhanced regulations for deepwater drilling offshore the United States may impact our oil and gas business located offshore in the Gulf of Mexico and reduce the need for our services in the Gulf of Mexico.
 
In April 2010, the Deepwater Horizon drilling rig experienced an explosion and fire, and later sank into the Gulf of Mexico.  The complete destruction of the Deepwater Horizon rig also resulted in a significant release of crude oil into the Gulf.  As a result of this explosion and oil spill, a moratorium was placed on offshore deepwater drilling in the United States, which was subsequently lifted on October 12, 2010 and replaced with enhanced safety standards for offshore deepwater drilling.  Under the enhanced safety standards, in order for an operator to resume deepwater drilling, it is required to comply with existing and newly developed regulations and standards, including Notice to Lessees (NTL), 2010-N05 (Safety NTL), NTL 2010-N06 (Environmental NTL) and the Interim Final Rule (Drilling Safety Rule), and NTL 210-N10 (Compliance and Evaluation NTL). BSEE also plans to conduct inspections of each deepwater drilling operation for compliance with BSEE’s regulations, including but not limited to the testing of blow out preventers, before drilling resumes. As companies resume operations, they will also need to comply with the Safety and Environmental Management System (SEMS Rule) within the deadlines specified by the regulation.  Additionally, each operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout, regardless of the company or operator involved.  During 2011, the Department of the Interior has established a mechanism relating to the availability of blowout containment resources, including our HFRS and these resources are now being regulated by the BOEM and BSEE.  It is also expected that the BOEM and BSEE will issue further regulations regarding deepwater offshore drilling.  Our contracting services business, a significant portion of which is in the Gulf of Mexico, provides development services to newly drilled wells, and therefore relies heavily on the industry’s drilling of new
 
 
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oil and gas wells.  In addition, growth in our oil and gas business and any potential disposition of that business will be affected by the ability to develop our portfolio of prospects.   We can provide no assurance regarding the timing of future drilling permits.  With respect to our services business, if the issuance of permits is significantly delayed, and if our vessels are not redeployed to other locations where we can provide our services at a profitable rate, our business, financial condition and results of operations would be materially affected.
 
  The potential increased costs of complying with new regulations on offshore drilling in the U.S. Gulf of Mexico following the Deepwater Horizon rig explosion, and potentially in other areas around the world, may impact our oil and gas business and reduce the need for our services in those areas.
 
The Deepwater Horizon rig explosion in the Gulf of Mexico and its aftermath has resulted in new regulations in the United States, which may result in substantial increases in costs or delays in drilling or other operations in the Gulf of Mexico, oil and gas projects becoming potentially non-economic, and a corresponding reduced demand for our services.   We cannot predict with any certainty the substance or effect of any new or additional regulations in the United States or in other areas around the world.  In addition, safety requirements or other governmental regulations could increase our costs of operation of our oil and gas business and impact our ability to divest the assets of that business. Likewise this could also result in increased costs of operating our contracting services business, and our potential consumers’ oil and gas projects becoming non-economic, which could also negatively affect the demand for our contracting services business.  If the United States or other countries where we operate enact stricter restrictions on offshore drilling or further regulate offshore drilling or contracting services operations, our business, financial condition and results of operations could be materially affected.
 
Government Regulation, including recent legislative initiatives, may affect demand for our services.
 
Numerous federal and state regulations affect our operations. Current regulations are constantly reviewed by the various agencies at the same time that new regulations are being considered and implemented. In addition, because we hold federal leases, the federal government requires us to comply with numerous additional regulations that focus on government contractors. The regulatory burden upon the oil and gas industry increases the cost of doing business and consequently affects our profitability.  Potential legislation and/or regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.  Exploration and development activities and the production and sale of oil and gas are subject to extensive federal, state, local and international regulations.  
 
Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous domestic and foreign governmental agencies issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials, including oil into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed.
 
A variety of regulatory developments, proposals or requirements and legislative initiatives have been introduced in the domestic and international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. For example, the U.S. Congress has from time to time considered legislation to reduce greenhouse gas emissions, and almost one-half of the states already have taken legal measures to reduce greenhouse gas emissions, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.
 
In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an “air pollutant” under the federal Clean Air Act and thus subject to future regulation.  In December 2009,
 
 
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the U.S. Environmental Protection Agency (the “EPA”) issued an “endangerment and cause or contribute finding” for greenhouse gases under the federal Clean Air Act, which allowed the EPA to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.   Since 2009, the EPA has issued regulations that, among other things, require a reduction of emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources.
 
Additionally, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring in 2010.   On November 9, 2010, the EPA expanded its greenhouse reporting rule to include onshore petroleum natural gas production, offshore petroleum and natural gas production, onshore natural gas processing, natural gas transmission, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export, and natural gas distribution facilities.   Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis, with reporting beginning in 2012 for emissions in 2011.
 
These regulatory developments and legislative initiatives may curtail production and demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect future demand for our products and services, which may in turn adversely affect our future results of operations.  In addition, changes in environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future. Such environmental liability could substantially reduce our net income and could have a significant impact on our financial ability to carry out our operations.
 
 In 2009, U.S. Customs and Border Protection (“CBP”) issued a proposed modification to its prior rulings regarding the application of the Jones Act to the carriage by foreign flag vessels of items relating to certain offshore activities on the OCS.  CBP withdrew the proposed modifications later that year.  In early 2010, CBP and its parent agency, Department of Homeland Security (“DHS”), initiated a proposed rulemaking that would have been subject to public comment following publication in the Federal Register.   The proposed rulemaking would have implemented the same modifications as the CBP 2009 proposal.   The agencies subsequently withdrew the proposed rulemaking before it was published in the Federal Register.  If DHS or CBP re-proposes a change to the application of the Jones Act similar to that originally proposed by CBP, and such proposal is adopted, this development could potentially lead to operational delays or increased operating costs in instances where we would be required to hire coastwise qualified vessels that we currently do not own, in order to transport certain merchandise to projects on the OCS. This could increase our costs of compliance and doing business and make it more difficult to perform pipelay or well operation services.
 
Beginning in 2011, the federal government has proposed to levy a tax on offshore production and to repeal a number of existing tax preferences for domestic oil and gas producers.  The tax preferences include, but are not limited to, the elimination of the immediate expensing of intangible drilling costs, the use of percentage depletion methodology in respect to oil and gas wells, the ability to claim the domestic manufacturing deduction against income derived from oil and gas production and other preference items.   The elimination of one or all of these tax preferences may have an adverse impact on our financial results in future years.   In addition, it is uncertain as to whether we will be able to recoup these additional tax costs from our customers.
 
Economic downturn and lower oil and natural gas prices could negatively impact our business.
 
Our operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry.  Certain economic data indicates the United States economy and the worldwide economy may require some time to recover from the recent global recession.  The consequences of a prolonged period of little or no economic growth will likely result in a lower level of activity and increased uncertainty regarding the direction of energy prices and the capital and commodity markets, which will likely contribute to decreased offshore exploration and drilling. A lower level of offshore exploration and drilling could have a material adverse effect on the demand for our services.  In addition, a general decline in the level of economic activity might result in lower commodity prices, which
 
 
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may also adversely affect our revenues from our oil and gas business and indirectly, our service business.  The extent of the impact of these factors on our results of operations and cash flow depends on the length and severity of the decreased demand for our services and lower commodity prices.
 
Continued market deterioration could also jeopardize the performance of certain counterparty obligations, including those of our insurers, customers and financial institutions.   Although we assess the creditworthiness of our counterparties, prolonged business decline or disruptions as a result of economic slow down or lower commodity prices could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts.  In the event any such party fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.
 
Lack of access to the credit market could negatively impact our ability to operate our business and to execute our business strategy.
 
Access to financing may be limited and uncertain, especially in times of economic weakness as witnessed in 2008 and 2009 and the developing situation in Europe, regarding the sovereign debt crisis of many participant countries in the European Union.  If the capital and credit markets are limited, we may incur increased costs associated with any additional financing we may require for future operations.  Additionally, if the capital and credit markets are limited, it could potentially result in our customers curtailing their capital and operating expenditure programs, which could result in a decrease in demand for our vessels and a reduction in fees and/or utilization. In addition, certain of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access the capital markets as needed to fund their business operations.  Likewise, our suppliers may be unable to sustain their current level of operations, fulfill  their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Continued lower levels of economic activity and weakness in the credit markets could also adversely affect our ability to implement our strategic objectives and dispose of non-core business assets.
 
Our forward-looking statements assume that our lenders, insurers and other financial institutions will be able to fulfill their obligations under our various credit agreements, insurance policies and contracts. If any of our significant financial institutions were unable to perform under such agreements, and if we were unable to find suitable replacements at a reasonable cost, our results of operations, liquidity and cash flows could be adversely impacted.
 
Concerns regarding the European debt crisis and market perceptions concerning the instability of the euro, the potential re-introduction of individual currencies within the Eurozone, or the potential dissolution of the euro entirely, could adversely affect the Company’s business, results of operations and financing.
 
As a result of the debt crisis with respect to countries in Europe, in particular most recently in Greece, Italy, Ireland, Portugal and Spain, the European Commission created the European Financial Stability Facility (the “EFSF”) and the European Financial Stability Mechanism (the “EFSM”) to provide funding to countries using the euro as their currency (the “Eurozone”) that are in financial difficulty and seek such support.  In March 2011, the European Council agreed on the need for Eurozone countries to establish a permanent financial stability mechanism, the European Stability Mechanism (the “ESM”), which will be activated by mutual agreement, to assume the role of the EFSF and the EFSM in providing external financial assistance to Eurozone countries after June 2013. Despite these measures, concerns persist regarding the debt burden of certain Eurozone countries and their ability to meet future financial obligations, the overall stability of the euro and the suitability of the euro as a single currency given the diverse economic and political circumstances in individual Eurozone countries. These concerns could lead to the re-introduction of individual currencies in one or more Eurozone countries, or, in more extreme circumstances, the possible dissolution of the euro currency entirely. Should the euro dissolve entirely, the legal and contractual consequences for holders of euro-denominated obligations would be determined by laws in effect at such time. These potential developments, or market perceptions concerning these and related issues, could adversely affect the value of the Company’s euro-denominated assets and obligations. In addition, concerns over the effect of this financial crisis on financial institutions in Europe and globally could have an adverse impact on the capital markets generally, and more specifically on the ability of the Company and its customers, suppliers and lenders to finance their respective businesses, to
 
 
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access liquidity at acceptable financing costs, if at all, on the availability of supplies and materials and on the demand for the Company’s services.
 
Our substantial indebtedness and the terms of our indebtedness could impair our financial condition and our ability to fulfill our debt obligations.
 
As of December 31, 2011, we had approximately $1.2 billion of consolidated indebtedness outstanding. The significant level of indebtedness may have an adverse effect on our future operations, including:
 
 
 
limiting our ability to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements;
 
 
increasing our vulnerability to a continued general economic downturn, competition and industry conditions, which could place us at a disadvantage compared to our competitors that are less leveraged;
 
 
increasing our exposure to potential rising interest rates because a portion of our current and potential future borrowings are at variable interest rates;
 
 
reducing the availability of our cash flow to fund our working capital requirements, capital expenditures, acquisitions, investments and other general corporate requirements because we will be required to use a substantial portion of our cash flow to service debt obligations;
 
 
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
 
 
limiting our ability to expand our business through capital expenditures or pursuit of acquisition opportunities due to negative covenants in senior secured credit facilities that place annual and aggregate limitations on the types and amounts of investments that we may make, and limiting our ability to use proceeds from asset sales for purposes other than debt repayment (except in certain circumstances where proceeds may be reinvested under criteria set forth in our credit agreements).
 
A prolonged period of weak economic activity, such as was experienced in late 2008 and in 2009, may make it increasingly difficult to comply with our covenants and other restrictions in agreements governing our debt.  Our ability to comply with these covenants and other restrictions may be affected by the economic conditions and other events beyond our control.  If we fail to comply with these covenants and other restrictions, it could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by the lenders, including foreclosure on our pledged collateral.
 
Our operations outside of the United States subject us to additional risks.
 
Our operations outside of the United States are subject to risks inherent in foreign operations, including, without limitation:
 
 
 
the loss of revenue, property and equipment from expropriation, nationalization, war, insurrection, acts of terrorism and other political risks;
 
 
increases in taxes and governmental royalties;
 
 
changes in laws and regulations affecting our operations, including changes in customs, assessments and procedures, and changes in similar laws and regulations that may affect our ability to move our assets in and out of foreign jurisdictions;
 
 
renegotiation or abrogation of contracts with governmental entities;
 
 
changes in laws and policies governing operations of foreign-based companies;
 
 
currency restrictions and exchange rate fluctuations;
 
 
world economic cycles;
 
 
restrictions or quotas on production and commodity sales;
 
 
limited market access; and
 
 
other uncertainties arising out of foreign government sovereignty over our international operations.
 
In addition, laws and policies of the United States affecting foreign trade and taxation may also adversely affect our international operations.
 
 
The Company’s consolidated financial results are reported in U.S. dollars while certain assets and other reported items are denominated in the currencies of other countries, creating currency translation risk.
 
The reporting currency for the Company’s consolidated financial statements is the U.S. dollar. Certain of the Company’s assets, liabilities, expenses and revenues are denominated in other countries’ currencies. Those assets, liabilities, expenses and revenues are translated into U.S. dollars at the applicable exchange rates to prepare the Company’s consolidated financial statements. Therefore, increases or decreases in exchange rates between the U.S. dollar and those other currencies affect the value of those items as reflected in the Company’s consolidated financial statements, even if their value remains unchanged in their original currency. Substantial fluctuations in the value of the U.S. dollar could have a significant impact on the Company’s results.
 
We may not be able to compete successfully against current and future competitors.
 
The businesses in which we operate are highly competitive. Several of our competitors are substantially larger and have greater financial and other resources than we have. If other companies relocate or acquire vessels for operations in  the Gulf of Mexico, North Sea, Asia Pacific or West Africa regions, levels of competition may increase and our business could be adversely affected. In the exploration and production business, some of the larger integrated companies may be better able to respond to industry changes including price fluctuations, oil and gas demand, political change and government regulations.
 
In addition, in a few countries, the national oil companies have formed subsidiaries to provide oilfield services for them, competing with services provided by us. To the extent this practice expands, our business could be adversely impacted.
 
The loss of the services of one or more of our key employees, or our failure to attract and retain other highly qualified personnel in the future, could disrupt our operations and adversely affect our financial results.
 
Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in commodity prices. Our continued success depends on the active participation of our key employees. The loss of our key people could adversely affect our operations.
 
In addition, the delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. Our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our industry is high, and the supply is limited. In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
 
If we fail to effectively manage our growth, our results of operations could be harmed.
 
We have a history of growing through acquisitions of large assets and acquisitions of companies. We must plan and manage our acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. If we fail to effectively manage current and future acquisitions, our results of operations could be adversely affected. Our growth has placed significant demands on our personnel, management and other resources. We must continue to improve our operational, financial, management and legal compliance information systems to keep pace with the growth of our business.


 
Certain provisions of our corporate documents and Minnesota law may discourage a third party from making a takeover proposal.
 
Our Articles of Incorporation give our board of directors the authority, without any action by our shareholders, to fix the rights and preferences on up to 4,994,000 shares of undesignated preferred stock, including dividend, liquidation and voting rights. In addition, our by-laws divide the board of directors into three classes. We are also subject to certain anti-takeover provisions of the Minnesota Business Corporation Act. We also have employment arrangements with all of our executive officers that require cash payments in the event of a “change of control.” Any or all of the provisions or factors described above may discourage a takeover proposal or tender offer not approved by management and the board of directors and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less for their shares than otherwise might be available in the event of a takeover attempt.
 
Risks Relating to our Contracting Services Operations
 
Our contracting services operations are adversely affected by low oil and gas prices and by the cyclicality of the oil and gas industry.
 
Conditions in the oil and natural gas industry are subject to factors beyond our control. Our contracting services operations are substantially dependent upon the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, development, drilling and production operations. The level of capital expenditures generally depends on the prevailing view of future oil and gas prices, which are influenced by numerous factors affecting the supply and demand for oil and gas, including, but not limited to:
 
 
 
worldwide economic activity;
 
 
demand for oil and natural gas, especially in the United States, Europe, China and India;
 
 
economic and political conditions in the Middle East and other oil-producing regions;
 
 
actions taken by the Organization of Petroleum Exporting Countries (“OPEC”);
 
 
the availability and discovery rate of new oil and natural gas reserves in offshore areas;
 
 
the cost of offshore exploration for and production and transportation of oil and gas;
 
 
the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;
 
 
the sale and expiration dates of offshore leases in the United States and overseas;
 
 
technological advances affecting energy exploration, production, transportation and consumption;
 
 
weather conditions;
 
 
environmental and other governmental regulations; and
 
 
tax laws, regulations and policies.
 
A sustained period of low drilling and production activity or lower commodity prices would likely have a material adverse effect on our financial position, cash flows and results of operations.
 
The operation of marine vessels is risky, and we do not have insurance coverage for all risks.
 
Marine construction involves a high degree of operational risk. Hazards, such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in marine operations. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. Damage arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on us. Moreover, we cannot assure you that we will be able to maintain adequate insurance in the future at rates that we consider reasonable. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts and limitations for wind storm damages. As construction activity expands into deeper water in the Gulf of Mexico and other deepwater basins of the world, a greater percentage of our revenues will be from
 
 
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deepwater construction projects that are larger and more complex, and thus riskier, than shallow water projects. As a result, our revenues and profits are increasingly dependent on our larger vessels. The current insurance on our vessels, in some cases, is in amounts approximating book value, which could be less than replacement value. In the event of property loss due to a catastrophic marine disaster, mechanical failure, collision or other event, insurance may not cover a substantial loss of revenues, increased costs and other liabilities, and therefore, the loss of any of our large vessels could have a material adverse effect on us.
 
Our contracting business typically declines in winter, and bad weather in the Gulf of Mexico or North Sea can adversely affect our operations.
 
Marine operations conducted in the Gulf of Mexico and North Sea are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the summer and fall when weather conditions are favorable for offshore exploration, development and construction activities. We typically have experienced our lowest utilization rates in the first quarter. As is common in the industry, we typically bear the risk of delays caused by some adverse weather conditions. Accordingly, our results in any one quarter are not necessarily indicative of annual results or continuing trends.
 
Certain areas in and near the Gulf of Mexico and North Sea experience unfavorable weather conditions including hurricanes and other extreme weather conditions on a relatively frequent basis. Substantially all of our facilities and assets offshore and along the Gulf of Mexico and the North Sea, including our vessels and structures on our offshore oil and gas properties, are susceptible to damage and/or total loss by these storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail both service and production operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because customers may curtail their development activities due to damage to their platforms, pipelines and other related facilities.
 
If we bid too low on a turnkey contract, we suffer adverse economic consequences.
 
A significant amount of our projects are performed on a qualified turnkey basis where described work is delivered for a fixed price and extra work, which is subject to customer approval, is billed separately. The revenue, cost and gross profit realized on a turnkey contract can vary from the estimated amount because of changes in offshore job conditions, variations in labor and equipment productivity from the original estimates, the performance of third parties such as equipment suppliers, or other factors. These variations and risks inherent in the marine construction industry may result in our experiencing reduced profitability or losses on projects.
 
Risks Relating to our Oil and Gas Operations
 
Exploration and production of oil and natural gas is a high-risk activity and is subject to a variety of factors that we cannot control.
 
Our oil and gas business is subject to all of the risks and uncertainties normally associated with the exploration for and development and production of oil and natural gas, including uncertainties as to the presence, size and recoverability of hydrocarbons. We may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and/or result in a total loss of our investment, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells.
 
Projecting future natural gas and oil production is imprecise. Producing oil and gas reservoirs eventually have declining production rates. Projections of production rates rely on certain assumptions regarding historical production patterns in the area or formation tests for a particular producing horizon. Actual production rates could differ materially from such projections. Production rates also can depend on a number of additional factors, including commodity prices, market demand and the political, economic and regulatory climate.
 
 
Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:
 
 
 
fires;
 
 
title problems;
 
 
explosions;
 
 
pressures and irregularities in formations;
 
 
equipment availability;
 
 
blow-outs and surface cratering;
 
 
uncontrollable flows of underground natural gas, oil and formation water;
 
 
natural events and natural disasters, such as loop currents, hurricanes and other adverse weather conditions;
 
 
pipe or cement failures;
 
 
casing collapses;
 
 
lost or damaged oilfield drilling and service tools;
 
 
abnormally pressured formations; and
 
 
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
 
If any of these events occurs, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.
 
Natural gas and oil prices are volatile, which makes future revenue uncertain.
 
Our financial condition, cash flow and results of operations depend in part on the prices we receive for the oil and gas we produce. The market prices for oil and gas are subject to fluctuation in response to events beyond our control, such as:
 
 
 
supply of and demand for oil and gas;
 
 
market uncertainty;
 
 
worldwide political and economic instability; and
 
 
government regulations.
 
Oil and gas prices have historically been volatile, and such volatility is likely to continue. Our ability to estimate the value of producing properties for acquisition or disposition, and to budget and project the financial returns of exploration and development projects is made more difficult by this volatility. In addition, to the extent we do not forward sell or enter into costless collars or swap financial contracts in order to hedge our exposure to price volatility, a dramatic decline in such prices could have a substantial and material effect on:
 
 
 
our revenues;
 
 
results of operations;
 
 
cashflow;
 
 
financial condition;
 
 
our ability to increase production and grow reserves in an economically efficient manner; and
 
 
our access to capital.
 
Our commodity price risk management related to some of our oil and gas production may reduce our potential gains from increases in oil and gas prices.
 
Oil and gas prices can fluctuate significantly and have a direct impact on our revenues. To manage our exposure to the risks inherent in such a volatile market, from time to time we have entered into contracts to financially hedge the future cash flow associated with our production. This means that a portion of our production is sold at a fixed price or within a fixed price range as a shield against dramatic price declines that could occur in the market. We have hedged a significant portion of our anticipated production for both 2012 and 2013 with such financial hedging contracts.  We may from time to time
 
 
29

 
engage in other hedging activities including the forward sale of future production. These hedging activities may limit our benefit from commodity price increases.
 
We are vulnerable to risks associated with the Gulf of Mexico because our oil and gas operations are located exclusively in that area and our proved reserves are concentrated in a limited number of fields.
 
Our concentration of oil and gas properties in the Gulf of Mexico makes us more vulnerable to the risks associated with operating in that area than our competitors with more geographically diverse operations. These risks include:
 
 
 
tropical storms and hurricanes, which are common in the Gulf of Mexico during certain times of the year;
 
 
extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage); and
 
 
interruption or termination of operations by governmental authorities based on environmental, safety or other considerations.
 
Any event affecting this area in which we operate our oil and gas properties may have an adverse effect on our financial position, results of operations and cash flow.  We also may incur substantial liabilities to third parties or governmental entities, which could have a material adverse effect on our financial condition, results of operations and cash flow.
 
All of our estimated proved reserves are located in the Gulf of Mexico and we have two fields, Bushwood located at Garden Banks Blocks 462, 463, 506 and 507 and Phoenix located at Green Canyon Blocks 236, 237, 238 and 282, that represents approximately 16% and 23%, respectively, of our total estimated proved reserves as of December 31, 2011.  If the proved reserves at these fields are affected by any combination of adverse factors our future estimates of proved reserves could be decreased, perhaps significantly, which may have an adverse effect on our future results of operations and cash flows.   Production from the Phoenix field totaled approximately 11,250 barrels per day in 2011 or 47% of our average daily production level.  If an adverse event were to occur to our wells or the HP I, which serves as the processing unit for the field’s production, our results of operations and cash flows would be adversely affected.
 
Estimates of crude oil and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material change in those conditions, or other factors affecting those assumptions, could impair the quantity and value of our crude oil and natural gas reserves.
 
This Annual Report contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows therefrom based upon reports for the years ended December 31, 2011 and 2010, prepared by independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC, as to oil and gas prices, drilling and operating expenses, capital expenditures, asset retirement costs, taxes and availability of funds. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development and production expenditures, operating expenses and asset retirement costs and quantities of recoverable oil and gas reserves may vary from those estimated in these reports. Any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. You should not assume that the present value of future net cash flows from our proved reserves referred to in this Annual Report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the average of oil and gas prices on the first day of the month for the past twelve months and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. In addition, if costs of abandonment are materially greater than our estimates, they could have an adverse effect on financial position, cash flows and results of operations.
 
 
Approximately 68% of our total estimated proved reserves are either PDNP, PDSI or PUD and those reserves may not ultimately be produced or developed.
 
As of December 31, 2011, approximately 18% of our total estimated proved reserves were PDNP, 9% were PDSI and approximately 42% were PUD. These reserves may not ultimately be developed or produced. Furthermore, not all of our PUD or PDNP may be ultimately produced during the time periods we have planned, at the costs we have budgeted, or at all, which in turn may have a material adverse effect on our results of operations and cash flow.
 
Reserve replacement may not offset depletion.
 
Oil and gas properties are depleting assets. We replace reserves through acquisitions, exploration and exploitation of current properties. Approximately 68% of our proved reserves at December 31, 2011 are PUD, PDSI and PDNP. Further, our proved producing reserves at December 31, 2011 are expected to experience annual decline rates ranging from 30% to 40% over the next ten years. If we are unable to acquire additional properties or if we are unable to find additional reserves through exploration or exploitation of our properties, our future cash flows from oil and gas operations could decrease.
 
We are, in part, dependent on third parties with respect to the transportation of our oil and gas production and in certain cases, third party operators who influence our productivity.
 
Notwithstanding our ability to produce hydrocarbons, we are dependent on third party transporters to bring our oil and gas production to the market. In the event a third party transporter experiences operational difficulties, due to force majeure including weather damage, pipeline shut-ins, or otherwise, this can directly influence our ability to sell commodities that we are able to produce. In addition, with respect to oil and gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:
 
 
 
refuse to initiate exploration or development projects;
 
 
initiate exploration or development projects on a slower or faster schedule than we would prefer;
 
 
delay the pace of exploratory drilling or development; and/or
 
 
drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.
 
The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.
 
Our oil and gas operations involve significant risks, and we do not have insurance coverage for all risks.
 
Our oil and gas operations are subject to risks incident to the operation of oil and gas wells, including, but not limited to, uncontrollable flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution and other risks, any of which could result in substantial losses to us. We maintain insurance against some, but not all, of the risks described above. As a result, any damage not covered by our insurance could have a material adverse effect on our financial condition, results of operations and cash flow.
 
Other Risks
 
Other risk factors could cause actual results to be different from the results we expect. The market price for our common stock, as well as other companies in the oil and natural gas industry, has been historically volatile, which could restrict our access to capital markets in the future. Other risks and uncertainties may be detailed from time to time in our filings with the SEC.
 
Many of these risks are beyond our control. In addition, future trends for pricing, margins, revenue and profitability remain difficult to predict in the industries we serve and under current market, economic and political conditions. Forward-looking statements speak only as of the date they are made and, except as required by applicable law, we do not assume any responsibility to update or revise any of our forward-looking statements.
 
 
None.
 
 
Since the beginning of 2009, dispositions of non-core business assets (see “Our Strategy” above) resulted in receipt of the following pre-tax proceeds:
 
•  
  
Approximately $55 million from the sale of individual oil and gas properties;
•  
  
$100 million from the sale of a total of 15.2 million shares of CDI common stock held by us to CDI in separate transactions in January and June 2009;
 •  
  
Approximately $404.4 million, net of underwriting fees, from the sale of a total of 45.8 million shares of CDI common stock held by us to third parties in separate public secondary offerings one each in June 2009 and September 2009 (for additional information regarding the sales of CDI common shares by us see Note 3); and
•  
  
$25 million for the sale of our subsurface reservoir consulting business in April 2009.
 
 
OUR VESSELS
 
We own a fleet of seven vessels and 40 ROVs, three trenchers, and two ROV Drills. We also lease five vessels and one ROV.  Currently all of our vessels, both owned and chartered, have DP capabilities specifically designed to respond to the deepwater market requirements. Our Seawell and Well Enhancer vessels have built-in saturation diving systems.
 
Listing of Vessels, Barges and ROVs Related to Contracting Services Operations(1)
 
 
 
 
 
Flag
State
Placed
in
Service(2)
 
Length
(Feet)
 
 
Berths
 
SAT
Diving
 
 
DP
Crane
Capacity
(tons)
CONTRACTING SERVICES:
             
Pipelay —
             
Caesar (3) 
Vanuatu
5/2010
482
220
DP
300 and 36
Express (3) 
Vanuatu
8/2005
531
132
DP
396 and 150
Intrepid (3) 
Bahamas
8/1997
381
89
Capable
DP
400
Floating Production Unit —
             
Helix Producer I (4) 
Bahamas
4/2009
528
95
DP
26 and 26
Well Operations —
             
Q4000 (5) 
U.S.
4/2002
312
135
DP
160 and 360; 600 Derrick
Seawell
U.K.
7/2002
368
129
Capable
DP
130 and 65 Derrick
Well Enhancer
U.K.
10/2009
432
120
Capable
DP
100 and 150 Derrick
Normand Clough  (6) 
Norway
11/2008
385
120
Capable
DP
250
Robotics —
             
41 ROVs,  3 Trenchers and 2 ROVDrills (3), (7) (8)
Various
Olympic Canyon (8) 
Norway
4/2006
304
87
DP
150
Olympic Triton (8) 
Norway
11/2007
311
87
DP
150
Island Pioneer (8) 
Vanuatu
5/2008
312
110
DP
140
Deep Cygnus (8) 
Panama
4/2010
400
92
DP
150 and 25
Stril Explorer (8) 
Isle of Man
10/2011
251
70
DP
60 and 10
 


 
(1)
Under government regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety set by government regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the USCG. ABS, BV, DNV and Lloyds are classification societies used by ship owners to certify that their vessels meet certain structural, mechanical and safety equipment standards.
   
(2)
Represents the date we placed the vessel in service and not the date of commissioning.
   
(3)
Subject to vessel mortgages (US ROVs and trenchers only) securing our Credit Agreement described in Note 9.
   
(4)
Following the initial conversion of this vessel from a former ferry vessel into a DP floating production unit, additional topside production equipment was added to the vessel and it was certified for oil and natural gas processing work in June 2010  (see “Production Facilities”).  The topside production equipment is subject to mortgages securing our  Credit Agreement (Note 9).
   
(5)
Subject to vessel mortgage securing our MARAD debt described in  Note 9.
   
(6)
Chartered by our Australian joint venture, in we which maintain a 50% ownership interest – Note 7
   
(7)
Average age of our fleet of ROVs, trenchers and ROV Drills is approximately 5.2 years.
   
(8)
Leased.  One ROV is leased, we own the remaining 40 ROVs.
 
The following table details the average utilization rate for our vessels by category (calculated by dividing the total number of days the vessels in this category generated revenues by the total number of calendar days in the applicable period) for the years ended December 31, 2011, 2010 and 2009:
 
     
Year Ended December 31,
 
     
2011
     
2010
     
2009
 
                         
Contracting Services:
                       
  Pipelay and robotics support
   
76
%
   
84
%
   
79
%
  Well operations
   
90
%
   
83
%
   
82
%
  ROVs
   
60
%
   
62
%
   
68
%
 
We incur routine drydock, inspection, maintenance and repair costs pursuant to Coast Guard regulations in order to maintain our vessels in class under the rules of the applicable class society. In addition to complying with these requirements, we have our own vessel maintenance program that we believe permits us to continue to provide our customers with well maintained, reliable vessels. In the normal course of business, we charter other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and additional robotics support vessels.
 
PRODUCTION FACILITIES
 
We own a 50% interest in Deepwater Gateway, a limited liability company in which Enterprise Products Partners L.P. is the other member.  Deepwater Gateway was formed to construct, install and own the Marco Polo TLP in order to process production from Anadarko Petroleum Corporation’s Marco Polo field discovery at Green Canyon Block 608, which is located in water depths of 4,300 feet.  Anadarko required processing capacity of 50,000 barrels of oil per day and 150 million cubic feet (Mmcf) of natural gas per day for its Marco Polo field.  The Marco Polo TLP was designed to process 120,000 barrels of oil per day and 300 Mmcf of natural gas per day and payload with space for up to six subsea tiebacks.
 
We also own a 20% interest in Independence Hub, an affiliate of Enterprise Products Partners L.P., that owns the Independence Hub platform, a 105 foot deep draft, semi-submersible platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet that serves as a regional hub for natural gas production from multiple ultra-Deepwater fields in the eastern Gulf of Mexico.  First production began in July 2007. The Independence Hub facility is capable of processing up to one Bcf per day of gas.


 
Further, we, along with Kommandor Rømø, a Danish corporation, formed Kommandor LLC and converted a ferry vessel into the HP I, a dynamically positioned floating production vessel.  The initial conversion of the HP I was completed in April 2009, and we have chartered the vessel from Kommandor LLC.  We own approximately 81% of Kommandor LLC.
 
After the initial conversion and our subsequent charter of the HP I, we installed, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the vessel.   The HP I is capable of processing up to 45,000 barrels of oil and 80 MMcf of natural gas daily.  We had planned for the vessel to be initially used at our Phoenix field; however, in June 2010 as we approached reestablishment of production from the Phoenix field, the vessel was contracted to assist in the Gulf oil spill response and containment efforts (Note 1).  Following these services, the HP I returned to the Phoenix field, where production commenced in October 2010.  The results of Kommandor LLC and the HP I are consolidated within our Production Facilities business segment (Note 17).
 
SUMMARY OF OIL AND NATURAL GAS RESERVE DATA
 
Accounting Rules Activities
 
 We adopted the oil and gas modernization disclosure rules on December 31, 2009 in conjunction with our year-end 2009 proved reserve estimates.  The most significant effect the adoption of these rules has had on our estimated reserve process is the use of the average oil and gas price for the year and the impact of the rules requiring development of proved undeveloped reserves within five years, which affected us in both 2011 and 2010 and could significantly impact future estimates of our proved reserves (see “Proved Undeveloped Reserves” below).
 
Internal Controls Over Reserve Estimation Process
 
 Our policies regarding internal controls over the recording of reserve estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Responsibility for compliance in reserves bookings is delegated to our Manager—Planning and Reserve Evaluation.
 
Our Manager—Planning and Reserve Evaluation prepares all reserve estimates covering all of our oil and gas properties.  Our Manager—Planning and Reserve Evaluation is the technical person primarily responsible for overseeing the preparation of our reserves estimates.  Our Manager—Planning and Reserve Evaluation attended Texas A&M University for his undergraduate and graduate studies in Petroleum Engineering and has over 11 years of industry experience with positions of increasing responsibility in engineering and reservoir evaluations.
 
We employ full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in conformance with SEC guidelines. Engineering reserve estimates were prepared by us based upon our interpretation of production performance data and sub-surface information derived from the drilling of existing wells. Our internal reservoir engineers analyzed 100% of our oil and gas fields on an annual basis (65 fields as of December 31, 2011).
 
Lastly, we engage a third party independent reservoir engineer firm to separately review our reserve estimation process and the results of this process.  We also separately engaged the independent reservoir engineer firm to prepare their own estimates of our proved reserves during each of the years ended December 31, 2011, 2010 and 2009.  Their report for the proved reserve estimates at December 31, 2011 is included herein as Exhibit 99.1 to this Annual Report.
 
The table below sets forth the approximate estimate of our proved reserves as of December 31, 2011.  Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions.
 
 
 
 
     
As of December 31, 2011
 
     
Proved Developed Reserves
     
Proved Undeveloped Reserves
     
Total Proved Reserves
 
                         
   Gas (Bcf)
   
59,859
     
37,162
     
97,021
 
   Oil (MBbls)
   
12,754
     
9,935
     
22,689
 
   Total (MBOE)
   
22,731
     
16,129
     
38,860
 
                         
 
Proved Undeveloped Reserves (“PUDs”)
 
At December 31, 2011, our PUDs totaled 37.2 Bcf of natural gas and 9.9 MMBbls of crude oil for a total of 16.1 MMBOE.  Our PUDs represent approximately 42% of our total estimates of proved oil and natural gas reserves at December 31, 2011.  At December 31, 2010 our estimated PUD reserves totaled 38.3 MMBOE.  All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained.  Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history.  Subsequent evaluation of the same reserves may result in variations which may be substantial.   This is especially valid as it pertains to PUD reserves.
 
At December 31, 2011, our most substantial PUDs  are located at our East Cameron Block 346 and Bushwood fields (see “Significant Oil and Gas Properties” below).   The East Cameron Block 346 field has estimated PUD reserves of approximately 4.3 MMBOE, which represents approximately 26% of our total PUD reserves and approximately 11% of our total estimated proved reserves.  Our Bushwood field has estimated PUDs totaling approximately 3.1 MMBOE, which represents approximately 19% of all our estimated PUD reserves and 8% of our total estimated proved reserves.   In 2011, we developed approximately 5.1 MMBOE of PUD reserves associated with four fields, including 0.9 MMBOE related to the Jake field that was sold in December 2011.  In 2010, we developed approximate 0.7 MMBOE of PUD reserves at our Gunnison field.
 
Costs incurred to develop PUDs totaled $78.2 million in 2011, $40.1 million in 2010 and $53.2 million in 2009.  All PUD drilling locations are expected to be drilled pursuant with the newly enacted requirements (see “Accounting Rules Activity” above).   Accordingly, estimated future development costs related to the development of PUDs are approximately $336.2 million at December 31, 2011.
 
For additional information regarding estimates of oil and gas reserves, including estimates of proved developed and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see Note 19.
 
Significant Oil and Gas Properties
 
Our oil and gas properties consist of interests in developed and undeveloped oil and gas leases. As of December 31, 2011, our exploration, development and production operations were located exclusively in the United States and located offshore in the Gulf of Mexico.   We have one inactive field, known as Camelot, located in the North Sea. We plan to substantially complete the abandonment of the Camelot field during 2012 in accordance with applicable United Kingdom regulations.
 
All of our production during 2011 and the 38.9 MMBOE of total estimated proved reserves at December 31, 2011 (approximately 68% of such total estimated reserves are PUDs, PDSI, and PDNP) is attributed to our properties located in the U.S. Gulf of Mexico.   The following table provides a brief description of our oil and gas properties we consider most significant to us at December 31, 2011:


 
     
 
 
 
Development Location
     
 
Net Total Proved Reserves (MMBOE)
     
 
Net Proved Reserves Mix
     
2011 Net Production (MMBOE)
     
Average WI%
     
Expected First Production
 
 
Oil %
 
 
Gas %
                                                     
  Deepwater
                                                   
    Bushwood(1)
   
U.S. GOM
     
6.2
     
9
 
91
     
1.3
     
51
     
Producing
 
    Phoenix(2)
   
U.S. GOM
     
8.8
     
77
 
23
     
4.1
     
70
     
Producing
 
    Gunnison(3)
   
U.S. GOM
     
2.3
     
81
 
19
     
0.3
     
19
     
Producing
 
  Outer Continental Shelf
                                                   
    East Cameron 346
   
U.S. GOM
     
5.2
     
81
 
19
     
0.1
     
75
     
Producing
 
    South Timbalier 86/63
   
U.S. GOM
     
3.7
     
45
 
55
     
0.4
     
91
     
Producing
 
    South Pass 89
   
U.S. GOM
     
1.2
     
30
 
70
     
0.1
     
27
     
Producing
 
    High Island A557
   
U.S. GOM
     
2.9
     
70
 
30
     
0.3
     
100
     
Producing
 
    South Marsh Island 130
   
U.S. GOM
     
2.4
     
81
 
19
     
0.5
     
100
     
Producing
 
    Ship Shoal 223/224
   
U.S. GOM
     
1.0
     
29
 
71
     
0.3
     
51
     
Producing
 
    Eugene Island 302
   
U.S. GOM
     
1.2
     
82
 
18
     
-
     
100
     
PDSI 2012
 
 
(1)
Garden Banks Blocks  462, 463, 506 and 507.  Although the Bushwood field is currently producing, there remains a significant amount of PUD reserves that we intend to develop in order to sustain future production from the field.
   
(2)
Green Canyon Blocks 236, 237, 238 and 282.
   
(3)
Third party operated property comprised of Garden Banks Blocks 625, 667, 668 and 669.
 
United States Offshore
 
Deepwater
 
The proved reserves estimates associated with our three fields in the Deepwater of the Gulf of Mexico totaled approximately 17.3 MMBOE or approximately 44% of our total estimated proved reserves at December 31, 2011. We operate both the Phoenix field and certain portions of the Bushwood field, representing approximately 87% of our Deepwater proved reserves.   Gunnison, a non-operated field, has been producing since December 2003.  In December 2011, we sold our ownership interest in the Jake field at Green Canyon Block 490 for gross proceeds of approximately $31 million.  The Jake field was substantially developed during 2011.  Our net production from our Deepwater properties totaled approximately 5.7 MMBOE in 2011 as compared to 4.5 MMBOE in 2010.  The increased production reflects the commencement of production from the Phoenix field in October 2010, and was partially offset by decreasing production from both the Bushwood and Gunnison fields.
 
Outer Continental Shelf
 
The estimated proved reserves for our 62 fields in the Gulf of Mexico on the OCS totaled approximately 21.6 MMBOE, or 56% of our total estimated proved reserves, as of December 31, 2011. Our net production from the OCS properties totaled approximately 3.0 MMBOE in 2011 and 3.4 MMBOE in 2010. Our largest field on the OCS is East Cameron Block 346, the total estimated proved reserves of which represents approximately 24% of our aggregated OCS estimated proved reserves (or approximately 13% of total estimated proved reserves). Only three other individual OCS fields represented over 5% of our total estimated proved reserves at December 31, 2011.  The South Timbalier Blocks 86/63 field represented approximately 17% of our total estimated OCS proved reserves (or approximately 10% of our total estimated proved reserves), the High Island Block 557 field represented approximately 14% of our total estimated OCS proved reserves (or approximately 7.5% of our total estimated proved reserves) and the South Marsh Island Block 130 field represented approximately 11% of total OCS proved reserves (approximately 6% of total estimated proved reserves).  We are the operator of 89% of our OCS properties the aggregate estimated proved reserves of which totals approximately 19.2 MMBOE .
 
 
As long as we continue to have interests in our oil and gas properties, we will continue to advance our development activities and may pursue additional future exploration opportunities primarily in the Deepwater of the Gulf of Mexico.
 
United Kingdom Offshore
 
In December 2006, we acquired the Camelot field, located in the North Sea, of which we subsequently sold a 50% interest in June 2007.  In February 2010, we acquired our joint interest partner and as a result we own a 100% interest in the Camelot field (Note 5).  We are now obligated to pay the entire asset retirement obligation for the field (estimated to approximate $27.3 million at December 31, 2011).  During 2011, we commenced abandonment of the Camelot field in accordance with the then applicable U.K. regulations.  We plan to substantially complete these abandonment activities in 2012.  In 2011, we recorded impairment charges totaling approximately $20 million to increase the estimated asset retirement obligation associated with this field following changes in certain U.K. regulations (Note 5).   Excluding these impairment charges, the results of our U.K. operations were immaterial for each of the three years ended  December 31, 2011, 2010 and 2009, respectively.
 
Production, Price and Cost Data
 
Production, price and cost data for our oil and gas operations in the United States are as follows:
 
     
Year Ended December 31,
 
     
2011
     
2010
     
2009
 
                         
Production:
                       
   Gas (Bcf)
   
17
     
27
     
27
 
   Oil (MMBbls)
   
6
     
3
     
3
 
   Total (MBOE)
   
8,694
     
7,870
     
7,297
 
                         
Average sales prices realized (including hedges):
                       
   Gas (per Mcf)(1) 
 
$
6.04
   
$
6.01
   
$
4.48
 
   Oil (per Bbl)
 
$
100.91
   
$
75.27
   
$
67.11
 
   Total (BOE)
 
$
79.26
   
$
52.78
   
$
41.98
 
                         
Average production cost per BOE
 
$
20.73
   
$
17.24
   
$
16.42
 
Average depletion and amortization per BOE
 
$
25.29
   
$
29.89
   
$
23.20
 
 
(1)  
Includes sales of natural gas liquids.
 
Productive Wells
 
The number of productive oil and gas wells in which we held interests as of December 31, 2011 is as follows:
 
     
Oil Wells
     
Gas Wells
     
Total Wells
 
     
Gross
     
Net
     
Gross
     
Net
     
Gross
     
Net
 
United States – Offshore
   
231
     
182
     
232
     
123
     
463
     
305
 
 
Productive wells are producing wells and wells capable of production.  The number of gross wells is the total number of wells in which we own a working interest.  A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. One or more completions in the same borehole are counted as one well in this table.


 
The following table summarizes non-producing wells and wells with multiple completions as of December 31, 2011:
 
     
Oil Wells
     
Gas Wells
     
Total Wells
 
     
Gross
     
Net
     
Gross
     
Net
     
Gross
     
Net
 
                                                 
Not producing  (shut-in)
   
77
     
56
     
128
     
67
     
205
     
123
 
Multiple completions
   
15
     
7
     
42
     
18
     
57
     
25
 
 
Developed and Undeveloped Acreage
 
The developed and undeveloped acreage (including both leases and concessions) that we held at December 31, 2011 is as follows:
 
     
Undeveloped
     
Developed
 
     
Gross
     
Net
     
Gross
     
Net
 
                                 
United States – Offshore
   
135,628
     
117,500
     
316,986
     
184,885
 
 
Developed acreage is acreage spaced or assignable to productive wells. A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
 
Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The current terms of our leases on undeveloped acreage are scheduled to expire as shown in the table below (the terms of a lease may be extended by drilling and production operations):
 
     
Offshore
 
     
Gross
     
Net
 
                 
2012
   
26,515
     
18,755
 
2013
   
30,760
     
30,760
 
2014
   
5,760
     
5,760
 
2015
   
5,760
     
5,760
 
2016
   
40,320
     
33,408
 
2017 and beyond
   
26,513
     
23,057
 
   Total
   
135,628
     
117,500
 
 
Drilling Activity
 
The following table shows the results of oil and gas wells drilled in the United States for each of the years ended December 31, 2011, 2010 and 2009:
 
     
Net Exploratory Wells
     
Net Development Wells
 
     
Productive
     
Dry
     
Total
     
Productive
     
Dry
     
Total
 
                                                 
Year ended December 31, 2011
   
     
     
     
     
     
 
Year ended December 31, 2010
   
     
     
     
1.0
     
     
1.0
 
Year ended December 31, 2009
   
0.3
     
     
0.3
     
     
     
 
 
No wells were drilled in the United Kingdom in 2011, 2010 or 2009. We did not have any wells in progress at December 31, 2011.
 
 
A productive well is an exploratory or development well that is not a dry hole. A dry hole is an exploratory or development well determined to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the table above and as defined in the rules and regulations of the SEC, is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, to the reporting of abandonment to the appropriate agency. See Note 5, for additional information regarding our oil and gas operations.
 
FACILITIES
 
Our corporate headquarters are located at 400 North Sam Houston Parkway, East, Suite 400, Houston, Texas. We own the Aberdeen (Dyce), Scotland facility and our Spoolbase in Ingleside, Texas.  All other facilities are leased.
 
Location
Function                                     
Size                           
Houston, Texas                                                        
Helix Energy Solutions Group, Inc.
Corporate Headquarters, Project
Management, and Sales Office
92,274 square feet
 
Helix Subsea Construction, Inc.
Corporate Headquarters
 
 
Energy Resource Technology
GOM, Inc.
Corporate Headquarters
 
 
 Helix Well Ops, Inc.
Corporate Headquarters, Project
Management, and Sales Office
 
 
Kommandor LLC
Corporate Headquarters
 
     
Houston, Texas                                                        
Canyon Offshore, Inc.
Corporate, Management and Sales Office
1.0 acre
(Building: 24,000 square feet)
     
Dallas, Texas                                                        
Energy Resource Technology
GOM, Inc.
Dallas Office
8,999 square feet
     
Ingleside, Texas                                                        
Helix Ingleside LLC
Spoolbase
120 acres
     
Dulac, Louisiana                                                        
Energy Resource
Technology GOM, Inc.
Shore Base
20 acres 1,720 square feet
     
Aberdeen (Dyce), Scotland            
Helix Well Ops (U.K.) Limited
Corporate Offices and Operations
3.9 acres
(Building: 42,463 square feet)
 
Canyon Offshore Limited
Corporate Offices, Operations and
Sales Office
 
 
Energy Resource Technology
(U.K). Limited
Corporate Offices
 
 


 
 
Location
Function                      
Size           
     
Perth, Australia                                                        
Helix Well Ops SEA Pty Ltd
Well Ops SEA Pty Ltd
2.3 acres
(Buildings: 36,706 square feet)
 
Helix Energy Services Pty Limited
 
 
Corporate Offices
 
 
     
Singapore                                                        
Canyon Offshore
International Corp
Corporate, Operations and Sales
22,486 square feet
 
Helix Offshore Crewing Service Pte. Ltd.
Corporate Headquarters
 
 
 
  On July 8, 2011, a shareholder derivative lawsuit styled City of Sterling Heights Police & Fire Retirement System v. Owen Kratz, et al. was filed in the United States District Court for the Southern District of Texas, Houston Division.  In the suit, the plaintiff makes claims against our Board of Directors, certain of our former directors, our top current and former executives and the independent compensation consultant to the Compensation Committee of our board of directors, for breaches of the fiduciary duty of loyalty, unjust enrichment and aiding and abetting the alleged breaches of fiduciary duty relating to the long-term equity awards granted in 2010 to certain of the Company’s executive officers.  The Company has filed a motion to dismiss the claim asserting that the plaintiff has not (i) pled specific facts excusing its failure to make pre-suit demand on the Company’s Board of Directors as required by Minnesota law; (ii) filed proper verification; or (iii) stated a claim.   A ruling regarding the motion is pending.
 
We have received value added tax (VAT) assessments from the State of Andhra Pradesh, India (the “State”) in the amount of approximately $28 million related to our subsea and diving contract in India entered into in December 2006 for the tax years 2007, 2008, 2009, and 2010.  The State claims we owe unpaid taxes related to products consumed by us during the period of the contract.  We are of the opinion that the State has arbitrarily assessed this VAT tax and has no foundation for the assessment and believe that we have complied with all rules and regulations as it relates to VAT in the State.  We also believe that our position is supported by law and intend to vigorously defend our position. However, the ultimate outcome of this assessment and our potential liability from it, if any, cannot be determined at this time. If the current assessment is upheld, it would have a material negative effect on our consolidated results of operations while also impacting our financial position.
 
 
 
The executive officers of Helix are as follows:
 
Name 
Age
Position                                                      
Owen Kratz
57
President and Chief Executive Officer and Director
Anthony Tripodo
59
Executive Vice President and Chief Financial Officer
Alisa B. Johnson
54
Executive Vice President, General Counsel and Corporate Secretary
Johnny Edwards
58
Executive Vice President — Oil & Gas
Clifford V. Chamblee 52 Executive Vice President — Contracting Services
Lloyd A. Hajdik
46
Senior Vice President — Finance and Chief Accounting Officer
 


 
Owen Kratz is President and Chief Executive Officer of Helix.  He was named Executive Chairman in October 2006 and served in that capacity until February 2008 when he resumed the position of President and Chief Executive Officer.  He was appointed Chairman in May 1998 and served as the Company’s Chief Executive Officer from April 1997 until October 2006.  Mr. Kratz served as President from 1993 until February 1999, and has served as a Director since 1990.  He served as Chief Operating Officer from 1990 through 1997.  Mr. Kratz joined Helix in 1984 and held various offshore positions, including saturation diving supervisor, and management responsibility for client relations, marketing and estimating.  From 1982 to 1983, Mr. Kratz was the owner of an independent marine construction company operating in the Bay of Campeche.  Prior to 1982, he was a superintendent for Santa Fe and various international diving companies, and a diver in the North Sea.  Mr. Kratz has a Bachelor of Science degree from State University of  New York (SUNY).
 
Johnny Edwards is Executive Vice President — Oil & Gas of Helix. He was named Executive Vice President — Oil & Gas in March 2010. Mr. Edwards joined the Company in its oil and gas subsidiary, Energy Resources Technology GOM, Inc. (ERT), in 1994. Mr. Edwards served as President of ERT since 2000. Prior to becoming President of ERT, Mr. Edwards held several positions with increasing responsibilities at ERT managing the engineering and acquisitions for the company. Mr. Edwards has been involved in the oil and gas industry for over 35 years. Prior to joining ERT, Mr. Edwards spent 19 years in a broad range of engineering, operations and management positions with ARCO Oil & Gas Co. Mr. Edwards has a Bachelor of Science degree in chemical engineering from Louisiana Tech University.
 
Anthony Tripodo was elected as Executive Vice President and Chief Financial Officer of Helix on June 25, 2008. Mr. Tripodo oversees the finance, treasury, accounting, tax, information technology, supply chain and corporate planning functions as well as oversight to ERT.  Mr. Tripodo was a director of Helix from February 2003 until June 2008.  Prior to joining Helix, Mr. Tripodo was the Executive Vice President and Chief Financial Officer of Tesco Corporation.  From 2003 through the end of 2006, he was a Managing Director of Arch Creek Advisors LLC, a Houston based investment banking firm. From 2002 to 2003, Mr. Tripodo was Executive Vice President of Veritas DGC, Inc., an international oilfield service company specializing in geophysical services. Prior to becoming Executive Vice President, he was President of Veritas DGC’s North and South American Group. From 1997 to 2001, he was Executive Vice President, Chief Financial Officer and Treasurer of Veritas. Previously, Mr. Tripodo served 16 years in various executive capacities with Baker Hughes, including serving as Chief Financial Officer of both the Baker Performance Chemicals and Baker Oil Tools divisions. Mr. Tripodo graduated Summa Cum Laude with a Bachelor of Arts degree from St. Thomas University (Miami).
 
Alisa B. Johnson joined the Company as Senior Vice President, General Counsel and Secretary of Helix in September 2006, and in November 2008 became Executive Vice President, General Counsel and Secretary of the Company. Ms. Johnson has been involved with the energy industry for over 20 years. Prior to joining Helix, Ms. Johnson worked for Dynegy Inc. for nine years, at which company she held various legal positions of increasing responsibility, including Senior Vice President and Group General Counsel — Generation. From 1990 to 1997, Ms. Johnson held various legal positions at Destec Entergy, Inc. Prior to that Ms. Johnson was in private law practice. Ms. Johnson received her Bachelor of Arts degree Cum Laude from Rice University and her law degree Cum Laude from the University of Houston.
 
Clifford V. Chamblee joined the Company in its ROV subsidiary, Canyon Offshore, Inc. (Canyon), in 1997. Mr. Chamblee served as President of Canyon from 2006 until 2011. Prior to becoming President of Canyon, Mr. Chamblee held several positions with increasing responsibilities managing the operations of Canyon including Senior Vice President and Vice President Operations from 1997 until 2006. Mr. Chamblee has been involved in the robotics industry for over 32 years. From 1988 to 1997, Mr. Chamblee held various positions with Sonsub International, Inc., including Vice President Remote Systems, Marketing Manager and Operations Manager.  From 1986 until 1988, he was Operations Manager and Superintendent for Cal Dive International, Inc. (now known as Helix).  From 1981 until 1986, Mr. Chamblee held various positions for Oceaneering International/Jered, including ROV Superintendent and ROV Supervisor.  Prior to 1981, he was an ROV Technician for Martech International.
 
 
Lloyd A. Hajdik joined the Company in December 2003 as Vice President — Corporate Controller.   Mr. Hajdik  became Chief Accounting Officer in February 2004 and in November 2008 he became Senior Vice President – Finance and Chief Accounting Officer. Prior to joining Helix, Mr. Hajdik served in a variety of accounting and finance-related roles of increasing responsibility with Houston-based companies, including  NL Industries, Inc., Compaq Computer Corporation (now Hewlett Packard), Halliburton’s Baroid Drilling Fluids and Zonal Isolation product service lines,  Cliffs Drilling Company and Shell Oil Company.   Mr. Hajdik was with Ernst & Young LLP in the audit practice from 1989 to 1995. Mr. Hajdik graduated Cum Laude from Texas State University receiving a Bachelor of Business Administration degree. Mr. Hajdik is a Certified Public Accountant and a member of the Texas Society of CPAs as well as the American Institute of Certified Public Accountants.
 
 
PART II
 
 
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HLX.” The following table sets forth, for the periods indicated, the high and low sale prices per share of our common stock:
 
 
   
Common Stock Prices
 
   
High
   
Low
 
2010
           
  First Quarter                                                   
  $ 14.80     $ 9.98  
  Second Quarter                                                   
  $ 17.00     $ 9.70  
  Third Quarter                                                   
  $ 11.32     $ 8.38  
  Fourth Quarter                                                   
  $ 14.48     $ 10.88  
                 
2011
               
  First Quarter                                                   
  $ 17.69     $ 10.92  
  Second Quarter                                                   
  $ 19.20     $ 14.57  
  Third Quarter                                                   
  $ 21.65     $ 12.65  
  Fourth Quarter                                                   
  $ 19.42     $ 11.57  
                 
2012
               
  First Quarter(1)                                                   
  $ 19.69     $ 15.55  
 
(1)
Through February 22, 2012
 
On February 16, 2012, the closing sale price of our common stock on the NYSE was $18.65 per share. As of February 16, 2012, there were 351 registered shareholders and 24,054 beneficial stockholders of our common stock.
 
We have never declared or paid cash dividends on our common stock and do not intend to pay cash dividends in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and growth of our business. In addition, our financing arrangements prohibit the payment of cash dividends on our common stock. See Management’s Discussion and Analysis of Financial Condition and Results of Operations “— Liquidity and Capital Resources.”
 
Shareholder Return Performance Graph
 
The following graph compares the cumulative total shareholder return on our common stock for the period since December 31, 2006 to the cumulative total shareholder return for (i) the stocks of 500 large-cap corporations maintained by Standard & Poor’s (“S&P 500”), assuming the reinvestment of dividends; (ii) the Philadelphia Oil Service Sector index (“OSX”), a price-weighted index of leading oil service companies, assuming the reinvestment of dividends; and (iii) a peer group selected by us
 
 
41

  
(the “Peer Group”) consisting of the following companies: ATP Oil & Gas Corporation, Atwood Oceanics Inc., Cameron International Corporation, Dril-Quip, Inc., Energy XXI (Bermuda) Limited, FMC Technologies, Inc., McDermott International, Inc., Oceaneering International, Inc., Oil States International, Inc., Petrofac Ltd, Rowan Companies, Inc., Stone Energy Corp., Superior Energy Services, Inc., TETRA Technologies, Inc., and W&T Offshore, Inc. The returns of each member of the Peer Group have been weighted according to each individual company’s equity market capitalization as of December 31, 2011 and have been adjusted for the reinvestment of any dividends. We believe that the members of the Peer Group provide services and products more comparable to us than those companies included in the OSX. The graph assumes $100 was invested on December 31, 2006 in our common stock at the closing price on that date price and on December 31, 2006 in the three indices presented. We paid no cash dividends during the period presented. The cumulative total percentage returns for the period presented were as follows: our stock — (49.6%); the Peer Group — 56.5%; the OSX — 8.2%; and S&P 500- (11.3)%. These results are not necessarily indicative of future performance.
 
Comparison of Five Year Cumulative Total Return among Helix, S&P 500,
OSX and Peer Group
 
   
As of December 31,
 
   
2006
     
2007
     
2008
     
2009
     
2010
     
2011
 
Helix
$
100.0
   
$
132.3
   
$
23.1
   
$
37.5
   
$
38.7
   
$
50.4
 
Peer Group Index
$
100.0
   
$
147.5
   
$
53.3
   
$
114.0
   
$
159.6
   
$
156.5
 
Oil Service Index
$
100.0
   
$
150.9
   
$
60.7
   
$
97.5
   
$
122.6
   
$
108.2
 
S&P 500
$
100.0
   
$
103.5
   
$
63.7
   
$
78.6
   
$
88.7
   
$
88.7
 
 
Source: Bloomberg
Issuer Purchases of Equity Securities
 
Period
 
(a) Total number
of shares
purchased (1)
   
(b) Average
price paid
per share
 
(c) Total number
of shares
purchased as
part of publicly
announced
program (2)
   
(d) Maximum
number of shares
that may yet be
purchased under
the program (3)
October 1 to October 31, 2011
 
498,851
 
$
13.06
 
497,412
   
November 1 to November 30, 2011
 
   
 
   
December 1 to December 31, 2011
 
265
   
16.91
 
   
   
499,116
 
$
13.06
 
497,412
   
 


 
(1)
Includes shares delivered to the Company by employees in satisfaction of minimum withholding taxes upon vesting of restricted shares.
(2)
Shares repurchased under previously announced stock buyback program (Note 14). In October 2011, we repurchased the then remaining available shares under stock buyback program.   Additional shares became available under the stock buyback program in January 2012 (see footnote (3) below).
(3)
Amount as of December 31, 2011.   In January 2012, we issued approximately 0.4 million shares to certain of our employees.  These grants will increase the number of shares available for repurchase by a corresponding amount (Note 12).
 
 
 
The financial data presented below for each of the five years ended December 31, 2011, should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included elsewhere in this Annual Report.
 
   
Year Ended December 31,
   
   
2011
   
2010
     
2009 (1)
     
2008
     
2007
   
   
(amounts in thousands, except per share data)
   
                                         
                                       
Net revenues
$
1,398,607
 
$
1,199, 838
   
$
1,461,687
   
$
2,114,074
   
$
1,732,420
   
Gross profit
 
330,592
   
33,672
     
243,162
     
372,191
     
505,907
   
Operating income (loss) (2) 
 
235,528
   
(94,656
)
   
203,815
     
(414,222
)
   
411,279
   
Equity in earnings of investments
 
22,215
   
19,469
     
32,329
     
31,854
     
19,573
   
Income (loss) from continuing operations
 
133,077
   
(124,153
)
   
166,170
     
(580,245
)
   
343,639
   
Income (loss) from discontinued operations, net of taxes
 
   
     
 
9,581
     
(9,812
)
   
1,347
   
Net income (loss), including noncontrolling interests(3)
 
133,077
   
(124,153
 
)
   
175,751
     
(590,057
)
   
344,986
   
Net (income) loss applicable to noncontrolling interests
 
(3,098
 
)
 
(2,835
 
)
   
(19,697
)
   
(45,873
)
   
(29,288
)
 
Net income (loss) applicable to Helix
 
129,979
   
(126,988
)
   
156,054
     
(635,930
)
   
315,698
   
Preferred stock dividends (4) 
 
(40
)
 
(114
)
   
(54,187
)
   
(3,192
)
   
(3,716
)
 
Net income (loss) applicable to Helix common shareholders
 
129,979
   
(127,102
 
)
   
 
101,867
     
(639,122
)
   
311,982
   
 Adjusted EBITDAX, less Cal Dive (5)
$
668,662
 
$
430,326
   
$
490,092
   
$
575,272
   
$
608,813
   
                                       
Basic earnings (loss) per share of common stock:
                                     
   Continuing operations
$
1.23
   
(1.22
)
 
$
0.92
   
$
(6.94
)
 
$
   3.40
   
   Discontinued operations
 
   
     
0.09
     
(0.11
)
   
0.02
   
   Net income (loss) per common share
$
1.23
 
$
(1.22
)
 
$
1.01
   
$
(7.05
)
 
$
3.42
   
                                       
Diluted earnings (loss) per share of common stock:
                                     
   Continuing operations
$
1.22
 
$
(1.22
)
 
$
0.87
   
$
(6.94
)
 
$
3.25
   
   Discontinued operations
 
   
     
0.09
     
(0.11
)
   
0.01
   
   Net income (loss) per common share
$
1.22
 
$
(1.22
)
 
$
0.96
   
$
(7.05
)
 
$
3.26
   
                                       
Weighted average common shares outstanding:
                                     
Basic
 
104,528
   
103,857
     
99,136
     
90,650
     
90,086
   
Diluted
 
104,953
   
103,857
     
105,720
     
90,650
     
95,647
   
 
(1)
Excludes the results of Cal Dive subsequent to June 10, 2009 following its deconsolidation from our consolidated financial statements (Notes 1, 2 and 3).
   
(2)
Oil and gas property impairment charges totaled $132.6 million in 2011, $181.1 million in 2010, $120.6 million in 2009, $920.0 million in 2008 and $64.1 million in 2007.  Our oil and gas impairment charges in the fourth quarter of 2008 totaled $896.9 million and included charges to reduce goodwill ($704.3 million) and certain oil and gas properties ($192.6 million) to their estimated fair value.   Also includes exploration expenses totaling $10.9 million in 2011, $8.3 million in 2010, $24.4  million  in 2009, $32.9 million in 2008 and $26.7 million in 2007.
 
 
 
 
 
(3)
In 2009, we had $77.3 million of gains on the sales of Cal Dive common stock held by us.  Also includes the impact of gains on Cal Dive equity transactions of $98.5 million for the year ended December 31, 2007.  See Note 3 for additional information related to our transactions involving Cal Dive common stock.
   
(4)
The amount in 2009, includes $53.4 million of beneficial conversion charges related to our convertible preferred stock (Note 11).
   
(5)
This is a non-GAAP financial measure.  See “Non-GAAP Financial Measures” below for an explanation of the definition and  use of such measure as well as a reconciliation of these amount to each year’s respective reported income (loss) from continuing operations.
 
   
As of December 31,
 
   
2011
     
2010
     
2009 (1)
     
2008
     
2007
 
   
(In thousands)
 
Working capital
$
548,066
   
$
373,057
   
$
197,072
   
$
287,225
   
$
48,290
 
Total assets
 
3,582,347
     
3,592,020
     
3,779,533
     
5,067,066
(2)
   
5,449,515
 
Long-term debt (including current maturities)
 
1,155,321
     
1,357,932
     
1,360,739
     
2,027,226
     
1,758,186
 
Convertible preferred stock
 
1,000
     
1,000
(3)
   
6,000
(3)
   
55,000
     
55,000
 
Total controlling interest shareholders’ equity
 
1,421,403
     
1,260,604
     
1,405,257
     
1,191,149
(2)
   
1,829,951
 
Noncontrolling interests
 
28,138
     
25,040
     
22,205
     
322,627
     
263,926
 
Total  equity
 
1,449,541
     
1,285,644
     
1,427,462
     
1,513,776
     
2,093,877
 
 
 
(1)
Reflects deconsolidation of Cal Dive effective June 10, 2009 (Notes 1, 2 and 3).
   
(2)
Includes the $907.6 million of impairment charges recorded to reduce goodwill, intangible assets with indefinite lives and certain oil and gas properties to their estimated fair values.
   
(3)
In 2010, the holder of the convertible preferred stock redeemed $5 million of our convertible preferred stock into 1.8 million shares of our common stock.   In 2009, the holder of the convertible preferred stock redeemed $49 million of our convertible preferred stock into 12.8 million shares of our common stock (Note 11).
   
 
Non-GAAP Financial Measures
 
A non-GAAP financial measure is generally defined by the SEC as one that purports to measure historical or future performance, financial position, or cash flows, but excludes amounts that would not be so adjusted in the most comparable measures under generally accepted accounting principles (GAAP).   We measure our operating performance based on EBITDAX, a non-GAAP financial measure, that is commonly used in the oil and natural gas industry but is not a recognized accounting term under GAAP.  We use EBITDAX to monitor and facilitate the internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required under our debt covenants.   We believe our measure of EBITDAX provides useful information to the public regarding our ability to service debt and fund capital expenditures and may help our investors understand our operating performance and to compare our results to other companies that have different financing, capital and tax structures.
 
We define EBITDAX as income (loss) from continuing operations plus income taxes, net interest expense and other, depreciation, depletion and amortization expense and exploration expenses.  We separately disclose our non cash oil and gas property impairment charges, which, if not material, would be reflected as a component of our depreciation, depletion and amortization expense. Because such impairment charges are material for most of the periods presented, we have reported them as a separate line item in the accompanying consolidated statements of operations.  Non cash impairment charges related to goodwill are also added back if applicable.


 
In our reconciliation of income (loss) including noncontrolling interests, we provide amounts as reflected in our accompanying consolidated financial statements unless otherwise footnoted.  This means that such amounts are recorded at 100% even if we do not own 100% of all of our subsidiaries.  Accordingly, to arrive at our measure of Adjusted EBITDAX, we deduct the non-controlling interests related to the adjustment components of EBITDAX, the adjustment components of EBITDAX of any discontinued operations, the gain or loss on the sale of assets, and the portion of our asset impairment charges that are considered cash-related charges.  Asset impairment charges that are considered cash are those that affect future cash outflows most notably those related to adjustment to our asset retirement obligations.
 
Other companies may calculate their measures of EBITDAX and Adjusted EBITDAX differently than we do, which may limit its usefulness as a comparative measure.  Because EBITDAX is not a financial measure calculated in accordance with GAAP, it should not be considered in isolation or as a substitute for net income (loss) attributable to common shareholders or cash flows from operations, but used as a supplement to that GAAP financial measure.  A reconciliation of our net income (loss) attributable to common shareholders to EBITDAX is as follows:
 
   
Year Ended December 31,
   
   
2011
   
2010
     
2009
     
2008
     
2007
   
   
(amounts in thousands)
   
Income (loss) from continuing operations
$
133,077
 
 
$
(124,153
 
)
 
$
 
166,170
 
$
 
(580,245
)
$
 
343,639
   
   Adjustments:
                                     
      Income tax provision (benefit)
 
14,903
   
(39,598
)
   
95,822
     
86,779
     
171,862
   
      Net interest expense and other
 
99,953
   
86,324
     
51,495
     
111,098
     
67,047
   
      Depreciation, depletion and amortization expense
 
311,103
   
317,116
     
262,617
     
333,726
     
329,798
   
      Asset impairment charges(1) 
 
149,730
   
200,066
     
121,855
     
919,986
     
75,865
   
      Exploration expenses
 
10,914
   
8,276
     
24,383
     
32,926
     
26,725
   
EBITDAX
 
719,680
   
448,031
     
722,342
     
904,270
     
1,014,936
   
   Adjustments:
                                     
      Non-controlling interest in Cal Dive
 
   
     
(44,785
)
   
(105,280
)
   
(61,404
)
 
      Non-controlling interest in Kommandor LLC
 
(4,060
)
 
(3,878
)
   
(3,344
)
   
102
     
(82
)
 
      Discontinued operations(2) 
 
   
(16
)
   
(290
)
   
3,242
     
3,696
   
      Gain on sales of assets
 
(5,278
)
 
(9,405
)
   
(79,362
)
   
(73,471
)
   
(202,064
)
 
      Asset impairments charges
 
(41,680
)
 
(4,406
)
   
(48,178
)
   
(13,031
)
   
   
ADJUSTED EBITDAX
$
668,662
 
$
430,326
   
$
546,383
 
$
 
715,832
 
$
 
755,082
   
                                       
ADJUSTED EBITDAX
$
668,662
 
$
430,326
   
$
546,383
 
$
 
715,832
 
$
 
755,082
   
Less Cal Dive, net of non-controlling interests
 
   
     
(56,291
)
   
(140,560
)
   
(146,269
)
 
ADJUSTED EBITDAX less Cal Dive
$
668,662
 
$
430,326
   
$
490,092
 
$
 
575,272
 
$
 
608,813
   
 
(1)  
Includes impairment charges related to our oil and gas properties, other than temporary losses on our equity investments and any impairment charges associated with goodwill and other intangible assets.   Amount in 2011 also includes a $6.6 million impairment charge related to our well intervention equipment in Australia (Note 2).  The amount in 2007 also includes $11.8 million related to Cal Dive’s impairment of an equity investment in Offshore Technology Solutions Limited.
(2)  
Amounts are associated with Helix RDS Limited, our former reservoir technology consulting company that we sold in April 2009 (Note 1).


 
The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements located in Item 8. “Financial Statements and Supplementary Data” of this Annual Report. Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Item 8. “Financial Statements and Supplementary Data” of this Annual Report.  The results of operations reported and summarized below are not necessarily indicative of future operating results.  This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. “Risk Factors” and located earlier in this Annual Report.
 
Executive Summary
 
Our Business
 
We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our oil and gas business is a prospect generation, exploration, development and production company. Employing our own key services and methodologies, we seek to lower finding and development costs, relative to industry norms.
 
Our Strategy
 
Over the past three years, we have focused on improving our balance sheet by increasing our liquidity through dispositions of non-core business assets, decreasing our planned capital spending and reducing the amount of our debt outstanding.   Our focus is to shape the future direction of the Company around our Contracting Services business that is comprised of our well operations, robotics and subsea construction services while supplementing these efforts with our production facilities business activities and the substantial cash flow associated with our oil and gas business through a combination of existing and/or future production from our properties and the sale of all or a portion of our oil and gas assets.
 
Since the beginning of 2009, we have generated approximately $600 million in pre-tax proceeds from dispositions of non-core business assets.  These transactions included approximately $55 million from the sale of individual oil and gas properties, over $500 million from the sale of our stockholdings in CDI and $25 million for the sale of our former reservoir consulting business.
 
Economic Outlook and Industry Influences
 
Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, spending for our contracting services fluctuates directly with the direction of oil and natural gas prices. However, some of our Contracting Services, more specifically our subsea construction services, will often lag drilling operations by a period of 6 to 18 months, meaning that even if there were a sudden increase in deepwater permitting and subsequent drilling in the Gulf of Mexico, it probably would still be some time before we would start securing any awarded projects. The performance of our oil and gas operations is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including but not limited to:


 
 
 
worldwide economic activity, including available access to global capital and capital markets;
 
 
demand for oil and natural gas, especially in the United States, Europe, China and India;
 
 
economic and political conditions in the Middle East and other oil-producing regions;
 
 
the effect of regulations on offshore Gulf of Mexico oil and gas operations;
 
 
actions taken by OPEC;
 
 
the availability and discovery rate of new oil and natural gas reserves in offshore areas;
 
 
the cost of offshore exploration for and production and transportation of oil and gas;
 
 
the ability of oil and natural gas companies to generate funds or otherwise obtain external capital for exploration, development and production operations;
 
 
the sale and expiration dates of offshore leases in the United States and overseas;
 
 
technological advances affecting energy exploration production transportation and consumption;
 
 
weather conditions;
 
 
environmental and other governmental regulations; and
 
 
tax policies.
 
Oil prices increased significantly in 2011 (the average price for West Texas Intermediate (“WTI”) crude oil was $94.88 per barrel in 2011 compared to $79.48 per barrel in 2010).  Commencing in the latter part of the first quarter of 2011, the price that we received for the majority of our crude oil sales volumes increased significantly over the WTI market price.   Historically the price we receive for most of our crude oil, as priced using a number of Gulf Coast crude oil price indexes, closely correlated with current market prices of WTI crude oil; however, because of a substantial increase in crude oil inventories at Cushing, Oklahoma the price of Gulf Coast crude is now substantially higher than WTI.  Currently the price we receive for our crude oil more closely correlates with the Brent crude oil price in the North Sea.
The premium we received for our oil sales was anywhere from $8-$25 per barrel greater than the given WTI price during the affected months in 2011.  We do not know how long the price variance of our crude oil and WTI will continue but most analysts believe this premium will continue over at least the first half of 2012.
 
Prices for natural gas have decreased significantly from the record highs in mid-2008 primarily reflecting the increased supply from non-traditional sources of natural gas such as production from shale formations and tight sands, as well as decreased demand following the economic downturn that commenced in mid-to-late 2008, and the currently warmer than expected winter conditions over most of the U.S.  Although there have been signs that the economy may be improving, most economists believe that the recovery will be slow and the economy will take time to recover to previous levels.  The oil and natural gas industry has been adversely affected by the uncertainty of the general timing and level of the economic recovery as well as the more recent uncertainties concerning increased government regulation of the industry in the United States (as further discussed below).
 
In April 2010, an explosion occurred on the Deepwater Horizon drilling rig located on the site of the Macondo well at Mississippi Canyon Block 252 (Note 1).  The resulting events included loss of life, the complete destruction of the drilling rig and an oil spill the magnitude of which was unprecedented in U.S. territorial waters.  In October 2010, the DOI lifted the deepwater drilling moratorium that had been in place since May 2010 and instructed the BOEMRE (now the BOEM and BSEE) that it could resume issuing drilling permits conditioned on the requesting company’s compliance with all revised drilling, safety and environmental requirements.  The BOEMRE resumed issuing deepwater drilling permits in late February 2011.   See below for a discussion of our HFRS, which currently represents one of the containment systems that have been included in deepwater drilling permit applications with BOEMRE (now the BOEM and BSEE) under its new guidelines.
 
While we did not have any plans to drill any additional deepwater wells during the period covered by the drilling moratorium in 2010, our contracting services businesses rely heavily on industry investment in the Gulf of Mexico and the results of this drilling moratorium and subsequent delay in the drilling permit process has adversely affected our results of operations and financial position.   Although our contracting services activities during 2010 remained substantially unaffected, delays in restarting drilling in the deepwater of the Gulf of Mexico, due to failure to issue permits or otherwise, have resulted in a deferral or cancellation of portions of our contracted backlog and have decreased current opportunities for contracts for work in the Gulf of Mexico and may continue to affect future opportunities for work in the Gulf of Mexico.  
 
 
47

 
Furthermore, the continuing delays in the permitting process and any subsequent related