UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

 

Commission file number 001-32936

 

 

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

 

(281) 618-0400
(Registrant’s telephone number, including area code)

 

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

 

 

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.   þ Yes  o No

 

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

 

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.  þ Yes  o  No

 

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, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2006 was $2,926,119,938 based on the last reported sales price of the Common Stock on June 30, 2006, as reported on the NASDAQ National Market System. On July 18, 2006, the registrant’s Common Stock began trading on the New York Stock Exchange.

 

The number of shares of the registrant’s Common Stock outstanding as of February 27, 2007 was 91,228,195.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2007, are incorporated by reference into Part III hereof.

 

 

HELIX ENERGY SOLUTIONS GROUP, INC. INDEX — FORM 10-K

 

Forward Looking Statements

 

This Annual Report on Form 10-K (“Annual Report”) contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

 

 

These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “achieve,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements.

 

Our actual results could differ materially from those anticipated in these 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.

 

OVERVIEW

 

Helix Energy Solutions Group, Inc. (“Helix”) is an international offshore energy company, incorporated in the state of Minnesota in 1979, that provides development solutions and other key services (contracting services operations) to the open energy market as well as to our own reservoirs (oil and gas operations). 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 (F&D) costs, relative to industry norms. Unless the context indicates otherwise, as used in this Annual Report, the terms “Company,” “we,” “us” and “our” refer collectively to Helix and its subsidiaries, including Cal Dive International, Inc. (collectively with its subsidiaries referred to as “Cal Dive” or “CDI”), our majority-owned subsidiary.

 

Our principal executive offices are located at 400 North Sam Houston Parkway East, Suite 400, Houston, Texas 77060; phone number 281-618-0400. Our stock trades on the New York Stock Exchange under the ticker symbol “HLX.” 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 report.

 

Please refer to the subsection “— Certain Definitions” on page 7 for definitions of additional terms used in this Annual Report.

 

CONTRACTING SERVICES OPERATIONS

 

We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing the economics especially from marginal fields. Those “life of field” services are organized in five disciplines: reservoir and well tech services, drilling, production facilities, construction and well operations. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Statement No. 131 Disclosures about Segments of an Enterprise and Related Information (“SFAS 131”): Contracting Services (which includes deepwater construction, well ops, reservoir and well tech services and in the future, drilling), Shelf Contracting and Production Facilities.

 

Construction

 

Since 1975, we have provided services in support of offshore oil and natural gas infrastructure projects involving the construction and maintenance of pipelines, production platforms, risers and subsea production systems primarily in the Gulf of Mexico. We provide construction services in two divisions: Deepwater and Shelf Contracting.

 

In the Deepwater division, we focus on construction services that provide the highest financial return from third-parties and add value to our oil and gas properties. Our deepwater construction services include pipelay, for which we own two deepwater pipelay vessels and are in the process of converting a third vessel (the Caesar), and robotics, for which we own 27 ROVs and four trenchers. We also provide construction services periodically from our well intervention vessels, the Seawell and Q4000. We provide these services primarily in the Gulf of Mexico, North Sea and Asia Pacific.

 

In our Shelf Contracting business segment, we perform traditional subsea services, including air and saturation diving, salvage work and shallow water pipelay on the OCS of the Gulf of Mexico, in water depths up to 1,000 feet. We believe that we are the market leader in the diving support business in the Gulf of Mexico OCS. We also provide these services in select international offshore markets, such as Asia Pacific and the Middle East. Within this segment we currently own and operate a diversified fleet of 26 vessels, including 23 surface and saturation diving support vessels capable of operating in water depths of up to 1,000 feet, as well as three shallow-water pipelay vessels. This division retained our former name “Cal Dive,” and we successfully completed a carve-out initial public offering (“IPO”) of that company in December 2006. We currently own a 73.0% interest in Cal Dive and have

consolidated the results of Cal Dive as of December 31, 2006. Cal Dive stock publicly trades on the New York Stock Exchange under the ticker symbol “DVR.”

 

Well Ops

 

We are the global leader in rig alternative subsea well intervention. Utilizing the Seawell in the North Sea and the Q4000 in the Gulf of Mexico, we engineer, manage and conduct well construction, intervention and decommissioning operations in water depths from 200 to 10,000 feet. With the increased demand for these services due to the growing number of subsea tree installations, coupled with the shortfall in rig availability, and, as a result, have committed to the construction of a newbuild North Sea vessel, the Well Enhancer. We have recently expanded geographically in Australia and Asia with the acquisition of a controlling interest in Seatrac, an established Australian well operations company now called Well Ops SEA Pty. Limited.

 

Production Facilities

 

When a production facility is required on a deepwater development, the cost can be a significant component of the F&D cost. We participate in the ownership of production facilities in hub locations where there is potential for significant subsea tieback activity (Marco Polo TLP and the Independence Hub). Ownership of production facilities enables us to earn a transmission company type return through tariff charges while providing construction work for our vessels. In addition, we are constructing a minimal floating production unit to be utilized on the Phoenix field (acquired in 2006 in the Gulf of Mexico) in a consolidated variable interest entity in which we own a 50% equity interest. Once production in this field ceases, this redeployable facility will be contracted to third parties or utilized on other internally owned reservoirs.

 

Reservoir and Well Tech Services

 

Until 2005, our reservoir and well tech services were an in-house service utilized solely with respect to our own wells and reservoirs. With the acquisition of Helix Energy Limited (“Helix RDS”) in 2005, which included a technical staff of over 160, we increased the resources that we can bring to our own projects as well as provide these services to our clients. With offices in Aberdeen, Perth, London and Kuala Lumpur, these services provide the market presence in regions we have identified as strategically important to future growth.

 

Drilling

 

This is a service we have not historically provided, but have been contemplating since the construction of the Q4000 five years ago. The drilling cost of a subsea deepwater development can be as much as 50% of the total F&D costs. We plan to add drilling capability to the Q4000 during 2007. The type of drilling intended for the Q4000 is a hybrid slim-bore technology capable of drilling and completing 6-inch slimbore wells to 22,000 feet total depth in up to 6,000 feet of water, which covers most of the deepwater prospects acquired in our acquisition of Remington Oil and Gas Corporation (“Remington”) during 2006 (see “— Oil and Gas Operations” below and Item 8. Financial Statements and Supplementary Data “— Note 4 — Acquisition of Remington Oil and Gas Corporation”), as well as having application on exploration and appraisal efforts for our clients.

 

OIL AND GAS OPERATIONS

 

In 1992, we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization and to achieve better returns than are likely through pure service contracting. Over the last 15 years we have evolved this business model to include not only mature oil and gas properties but also proved reserves yet to be developed, and most recently, with the acquisition of Remington, an exploration, development and production company. This has led to the assembly of services that allows 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. As of December 31, 2006 we had 536 Bcfe of proved reserves with 91% of that located in the Gulf of Mexico.

 

Significant financial information relating to our operations by segments and by geographic areas for the last three years is contained in Item 8. Financial Statements and Supplementary Data “— Note 18 — Business Segment Information”. Within Contracting Services for financial reporting purposes, we have disclosed separately the financial information for Shelf Contracting and Production Facilities.

 

THE INDUSTRY AND OUR STRATEGY

 

The offshore oil and gas industry originated in the early 1950s as producers began to explore and develop the new frontier of offshore fields. The industry has grown significantly since the 1970s with service providers taking on greater roles on behalf of the producers. Industry standards were established during this period largely in response to the emergence of the North Sea as a major province leading the way into a new hostile frontier. The methodologies and standards involved were driven by the requirement of mitigating the risk of developing relatively large reservoirs in a then challenging environment. These standards are still largely adhered to today for all developments even if they are small and the frontier is more understood. There are factors we believe will influence the industry in the coming years: (1) increasing world demand for oil and natural gas; (2) peaking global production rates; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing ratio of contribution to global production from marginal fields; (6) increasing offshore activity; and (7) increasing number of subsea developments. Our two stranded strategy of combining contracting services operations and oil and gas operations allows us to focus on trends (4) to (7) 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 in which we have an equity stake. By “marginal”, we mean reservoirs that are no longer wanted by major operators or are too small to be material to them.

 

We provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing the economics from marginal fields. Our goal is for our oil and gas operations to generate prospects and find and develop oil and gas employing our key services and methodologies resulting in a 20% reduction in F&D costs. Meeting this objective drives our ability to achieve our primary goal of achieving a return on invested capital of 15% or greater. In order to achieve these goals we will:

 

Continue to Add Capacity to Key Services.  We will focus on services that provide the highest financial return and, at the same time, add value by lowering F&D costs on our oil and gas properties. We will commit capital to add capacity in these areas. Current initiatives include:

 

 

Generate Prospects and Focus Exploration Drilling on Low Risk Shallow Water Program and Deepwater Prospects Which Can Be Drilled with the Q4000.  In July 2006 we acquired Remington, an independent oil and gas exploration and production company with operations in the Gulf of Mexico. This acquisition brought not only proved producing reserves, but also a portfolio of prospects and a proven prospect-generating team. Remington had a proven track record of cost effectively turning prospects into production on the OCS and we believe similar success can occur in the deepwater. Of the 22 prospects we currently have in the Deepwater, 16 of them can be drilled with the Q4000 once the drilling upgrade is completed. We plan to seek partners on these prospects to enhance financial results on the drilling and development work as well as mitigate risk.

 

Focus on Exploitation Activities and Converting PUD/PDNP Reserves into Production.  Over the years our oil and gas operations have been able to achieve a significant return on capital due in part to their ability to convert PUD reserves from the proved undeveloped category to the proved developed category through exploitation drilling

and well work. As of December 31, 2006, we had 55% of our proved reserves, or 300 Bcfe in the PUD category. We will focus on cost effectively developing these reserves to production, or alternatively, selling them.

 

Seek to Monetize Services and Assets which are not Critical to Minimizing F & D Costs.  As stated previously, we will focus on services which are critical to lowering F&D costs, particularly on marginal fields in the deepwater. As the strategy of our Shelf Contracting segment does not focus on minimizing F&D cost, in December 2006, a minority stake (26.5%) in this business was sold through a carve-out initial public offering. Subject to market conditions, we may sell additional interests in this subsidiary in the future. In addition, from time to time we intend to sell certain production assets, particularly once the contracting services work relating to the asset has been completed.

 

International Expansion of the Model.  We regard the North Sea and certain areas of the Far East as targets for the expansion of our business model. We have built a strong service presence in the North Sea and recently acquired our first mature oil and gas property in that area. In Asia Pacific, we completed two important service acquisitions in 2006 and will seek to grow our business there in a measured way over the near term.

 

Certain Definitions

 

Defined below are certain terms helpful to understanding our business:

 

Bcfe:  Billions of cubic feet equivalent, used to describe oil volumes converted to their energy equivalent in natural gas as measured in billions of cubic feet.

 

Deepwater:  Water depths beyond 1,000 feet.

 

Dive Support Vessel (DSV):  Specially equipped vessel that performs services and acts as an operational base for divers, ROVs and specialized equipment.

 

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 pursuant to which the redundancy allows the vessel to maintain position even with 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 are necessary to provide the redundancy required to support safe deployment of divers, while only a single DP system is necessary to support ROV operations.

 

EHS:  Environment, Health and Safety programs to protect the environment, safeguard employee health and eliminate injuries.

 

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.

 

IMR:  Inspection, maintenance and repair activities.

 

Life of Field Services:  Services performed on offshore facilities, trees and pipelines from the beginning to the economic end of the life of an oil field, including installation, inspection, maintenance, repair, contract operations, well intervention, recompletion and abandonment.

 

MBbl:  When describing oil, refers to 1,000 barrels containing 42 gallons each.

 

Minerals Management Service (MMS):  The federal regulatory body for the United States having responsibility for the mineral resources of the United States OCS.

 

MMcf:  When describing natural gas, refers to 1 million cubic feet.

 

Moonpool:  An opening in the center of a vessel through which a saturation diving system or ROV may be deployed, allowing safe deployment in adverse weather conditions.

 

MSV:  Multipurpose support vessel.

 

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:  Defined in this Annual Report as comprising Global Industries, Ltd. (NASDAQ: GLBL), Acergy US, Inc. (NASDAQ: ACGY), Oceaneering International, Inc. (NYSE: OII), Technip-Coflexip (NYSE: TKP), Superior Energy Services, Inc. (NYSE: SPN), TETRA Technologies, Inc. (NYSE: TTI) and Subsea 7.

 

Oil and Gas:  Defined in this Annual Report as comprising Newfield Exploration Company (NYSE: NFX); ATP Oil & Gas Corp (NASDAQ: ATPG); W&T Offshore, Inc. (NYSE: WTI); Energy Partners, Ltd. (NYSE:EPL); and Mariner Energy, Inc. (NYSE: ME).

 

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, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells that require additional completion work or future recompletion prior to the start of production.

 

Proved Undeveloped Reserve (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.

 

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.

 

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 generally short in duration and often of a turnkey nature. These projects often require constant rescheduling and the availability or interchangeability of multiple vessels.

 

Stranded Field:  Smaller PUD reservoir that standing alone may not justify the economics of a host production facility and/or infrastructure connections.

 

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 Deepwater compliant structure designed for offshore hydrocarbon production.

 

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.

 

Ultra-Deepwater:  Water depths beyond 4,000 feet.

 

CONTRACTING SERVICES OPERATIONS

 

We provide a full range of contracting services in both the shallow water and deepwater primarily in the Gulf of Mexico, North Sea and Asia Pacific. Our services include:

 

 

Our strategic focus is to provide services and methodologies which we believe are critical to the finding and development of offshore reservoirs and maximizing the economics from marginal fields. Those “life of field” services are organized in five disciplines: reservoir and well tech services, drilling, production facilities, construction and well operations.

 

Construction

 

Deepwater

 

Construction services which we believe are critical to the development of marginal fields in the Deepwater are pipelay and robotics. We currently own three deepwater umbilical and pipelay vessels. The Intrepid is a 381 foot DP-2 vessel capable of laying rigid and flexible pipe (up to 12”) and umbilicals. The Express, which was acquired in the Torch Offshore Inc. (“Torch”) acquisition in 2005, is a 502 foot DP-2 vessel also capable of laying rigid and flexible pipe (up to 14”) and umbilicals. In January 2006, we acquired the Caesar, a mono-hull built in 2002 for the cable lay market. The vessel is 485 feet long and already has a state-of-the-art DP-2 system. We plan to convert this vessel to a Deepwater pipelay asset capable of laying rigid pipe up to 42” in diameter. The total estimated cost to acquire and convert the vessel is $137.5 million and the conversion should be completed by late 2007. We also periodically provide construction services from our well intervention vessels, Seawell and Q4000.  Our Deepwater and Well Ops divisions have backlog of over $380 million for certain of our deepwater vessels as of the end of 2006.

 

Our subsidiary, Canyon Offshore, Inc., operates ROVs and trenchers designed for offshore construction, rather than supporting drilling rig operations. As marine construction support in the Gulf of Mexico and other areas of the world moves to deeper waters, ROV systems play an increasingly important role. Our vessels add value by supporting deployment of our ROVs. We have positioned ourselves to provide our customers with vessel availability and schedule flexibility to meet the technological challenges of these Deepwater construction developments in the Gulf and internationally. Our 27 ROVs and four trencher systems operate in three regions: the Americas, Europe/West Africa and Asia Pacific. In addition, we plan to acquire five new work class ROVs and a combination robotic plow/trencher in 2007 for approximately $37 million.

 

The results of our Deepwater division are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 18 — Business Segment Information.”

 

Shelf Contracting

 

In shallower waters we provide manned diving, pipelay and pipe burial services to the offshore oil and natural gas industry. Based on the size of our fleet, we believe that we are the market leader in the diving support business, which involves services such as construction, inspection, maintenance, repair and decommissioning of offshore production and pipeline infrastructure, on the Gulf of Mexico OCS. We also provide these services directly or through partnering relationships in select international offshore markets, such as the Middle East and Asia Pacific.

Within this segment we currently own and operate a diversified fleet of 26 vessels, including 23 surface and saturation diving support vessels as well as three shallow water pipelay vessels. We believe that our fleet of diving support vessels is the largest in the world.

 

Our Shelf Contracting services, including saturation, surface and mixed gas diving, enable us to provide a full complement of marine contracting services in water depths of up to 1,000 feet. We provide our saturation diving services in water depths of 200 to 1,000 feet through our fleet of eight saturation diving vessels and eight portable saturation diving systems. We also believe that our fleet of diving support vessels is among the most technically advanced in the industry because a number of these vessels have features such as dynamic positioning, or DP, hyperbaric rescue chambers, multi-chamber systems for split-level operations and moon pool deployment, which allow us to operate effectively in challenging offshore environments. We provide surface and mixed gas diving services in water depths typically less than 300 feet through our 15 surface diving vessels. Shelf Contracting also has three vessels dedicated exclusively to pipelay and pipe burial services in water depths of up to approximately 400 feet. Pipelay and pipe burial operations typically require extensive use of our diving services; therefore, we consider these services to be complementary.

 

In the last 18 months, we have substantially increased the size of our Shelf Contracting fleet and expanded our operating capabilities on the Gulf of Mexico OCS through strategic acquisitions of Acergy US, Inc. (formerly known as Stolt Offshore, Inc.) (“Acergy”), and the assets of Torch. Pursuant to our growth strategy, we also acquired Fraser Diving International Limited (“Fraser”).

 

The Shelf Contracting division retained our former name of “Cal Dive,” and completed a carve-out initial public offering in December 2006. It trades on the New York Stock Exchange under the ticker symbol of “DVR.” We received pre-tax net proceeds of $464.4 million, which included the sale of a 26.5% interest and transfer of debt to the subsidiary. Together with the shares issued to CDI employees immediately after the initial public offering, at December 31, 2006, we still retain 73.0% interest in CDI and have consolidated the results of Cal Dive.

 

Well Ops

 

In both the Gulf of Mexico and the North Sea, the increased number of subsea wells installed, the increasing value of the product, and the shortfall in both rig availability and equipment have resulted in an increased demand for Well Ops services.

 

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 zones or perform recompletions. Two of our vessels serve as work platforms for well ops services at costs significantly less than drilling rigs. In the Gulf of Mexico, our multi-service semi-submersible, the Q4000, has set a series of well operations “firsts” in increasingly deep water without the use of a rig. In the North Sea, the Seawell has provided intervention and abandonment services for over 500 North Sea wells since 1987. Competitive advantages of our vessels stem from their lower operating costs, together with an ability to mobilize quickly and to maximize production time by performing a broad range of tasks for intervention, construction, inspection, repair and maintenance. These services provide a cost advantage in the development and management of subsea reservoir developments. With the increased demand for these services due to the growing number of subsea tree installations coupled with the shortfall in rig availability, we have significant backlog for both working assets and have committed to the construction of a newbuild North Sea vessel, the Well Enhancer.

 

The results of Well Ops are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 18 — Business Segment Information.”

 

Production Facilities

 

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 invest in over-sized facilities that allow operators of these fields to tie back without burdening the operator of the hub reservoir. We are well positioned to facilitate the tie back of the smaller reservoir

to these hubs through our services and production groups. At the Marco Polo field, our 50% ownership in the production facility through Deepwater Gateway, L.L.C. (“Deepwater Gateway”) allows us to realize a return on our investment consisting of both a fixed monthly demand charge and a volumetric tariff charge. In addition, we assisted with the installation of the TLP and will work to develop the surrounding acreage that can be tied back to the platform by our construction vessels. Our 20% interest in the Independence Hub platform, scheduled for installation in mid 2007, should enable us to repeat the Marco Polo strategy.

 

When a hub is not feasible, we intend to apply an integrated application of our services in a manner that cumulatively lowers development costs to a point that allows for a small dedicated facility to be used. This strategy will permit the development of some fields that otherwise would be non-commercial to develop. The commercial risk is mitigated because we have a portfolio of reservoirs and the assets to redeploy the facility. For example, we are currently converting a ferry vessel into a minimal floating production unit. This facility will first be utilized on the Phoenix field (formerly known as Typhoon) 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 area ceases, this redeployable facility will be moved to a new location, contracted to a third party, or used to produce other internally-owned reservoirs.

 

Reservoir and Well Tech Services

 

In 2005 we acquired Helix RDS. Helix RDS is the largest outsource provider of sub-surface technology skills in the North Sea. With offices in Aberdeen, London, Kuala Lumpur and Perth, the more than 160 employees are organized around a core team concept. Each team, assigned to a specific client, contains a diverse set of skills, including reservoir engineering, geologists, modeling, flow assurance, completions, well design and production enhancement. The acquisition allows us to offer, as an outsource service, one of the most comprehensive sets of sub-surface skills of any company our size. The acquisition also provides sufficient capacity to have these skills available for our own production. The results of reservoir and well tech services are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data “— Note 18 — Business Segment Information.”

 

Drilling

 

With the well engineering skill sets in Helix RDS and the portfolio of Deepwater prospects acquired with Remington, we made the decision to add drilling capability to the Q4000. The type of drilling intended for the Q4000 is a hybrid slimbore technology which result in a smaller well bore diameter from a traditional rig. The vessel will be capable of drilling and completing 6-inch slimbore wells to 22,000 total depth in up to 6,000 feet of water and will also be able to drill a 4-inch bore to 22,000 total depth in up to 10,000 feet of water. There is great commercial application for this type of drilling with marginal reservoir sizes in 6,000 feet of water. The Q4000 will be capable of providing most of our oil and gas operations’ drilling needs in the deeper water. Drilling equipment for the Q4000 is scheduled to be installed mid-2007.

 

Assuming successful application of this technology, we expect internal need and market demand to create the conditions that will warrant the construction of the next Q-vessel (the H4500).

 

OIL & GAS OPERATIONS

 

We formed our oil and gas operations in 1992 to exploit a market opportunity to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services business and to achieve better returns than are likely through pure service contracting. Over the last 15 years we have evolved the model to include not only mature oil and gas properties but also proved reserves yet to be developed and most recently, the acquisition of Remington, an exploration, development and production company. This has led to the assembly of services that allows 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. As of December 31, 2006, we had 536 Bcfe of proved reserves with 91% located in the Gulf of Mexico.

 

Our oil and gas operations now seek to be involved in the reservoir at any stage of its life if we can apply our methodologies. The cumulative effect of our model is the ability to meaningfully improve the economics of a reservoir that would otherwise be considered non-commercial or non-impact, as well as making us a value adding partner to producers. Our expertise, along with similarly aligned interests, allows us to develop more efficient relationships with other producers. With a focus on acquiring non-impact reservoirs or mature fields, our approach taken as a whole is, itself, a service in demand by our producer clients and partners. As a result, during 2005, we were successful in acquiring equity interests in several deepwater undeveloped reservoirs. Developing these fields over the next few years will require meaningful capital commitments but will also provide significant backlog for our construction assets.

 

In July 2006, we acquired Remington for approximately $1.4 billion in cash and Helix stock and the assumption of $349.6 million of liabilities. Remington was an exploration, development and production company with operations primarily in the Gulf of Mexico. Remington has a significant prospect inventory, mostly in the Deepwater, which we believe will likely generate over $1 billion of life of field services for our vessels. As stated previously, our strategy is to focus exploration drilling primarily on low risk OCS prospects and Deepwater prospects which can be drilled with the Q4000. The Remington acquisition brought not only producing reserves, but also a portfolio of prospects and a proven prospect-generating team. Remington had a proven track record of cost effectively turning prospects into production on the OCS and we believe similar success will occur in the Deepwater. Of the 22 prospects we currently have in the Deepwater, 16 of them can be drilled with the Q4000, once the drilling upgrade to the vessel is completed. We plan to seek partners on these prospects to enhance financial results on the drilling and development work as well as mitigate risk.

 

We identify prospective oil and gas properties primarily by using 3-D seismic technology. After acquiring an interest in a prospective property, we drill one or more exploratory wells. If the exploratory well(s) find commercial oil and/or gas reserves, we complete the well(s) and begin producing the oil or gas. Because most of our operations are located in the offshore 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.

 

Within oil and gas operations, we have assembled a team of personnel with experience in geology, geophysics, reservoir engineering, drilling, production engineering, facilities management, lease operations and petroleum land management. Our oil and gas operations generate income in a number of ways: mitigating abandonment liability risk, lowering development time and cost, mitigating finding (exploration) costs, operating the field more effectively, and having a focus on extending the reservoir life through well exploitation operations. When a company sells an OCS property, it retains the financial responsibility for plugging and decommissioning if its purchaser becomes financially unable to do so. Thus, it becomes important that a property be sold to a purchaser who has the financial wherewithal to perform its contractual obligations. Although there is significant competition in this mature field market, our oil and gas operations’ reputation, supported by Helix’s financial strength, has made it the purchaser of choice of many major and independent oil and gas companies. In addition, our reservoir engineering and geophysical expertise, and having access to service assets and an ability to impact development costs, have made us a preferred partner in 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 can a non-operating interest owner. See “Item 2. Properties — Summary of Natural Gas and Oil Reserve Data” for detailed disclosures of our oil and gas properties.

 

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 construction services required by any particular contracting customer depends on the size of that customer’s capital expenditure budget devoted to construction plans 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 of major customers was as follows: 2006 — Louis Dreyfus Energy Services (10%)

and Shell Offshore, Inc. (10%); 2005 — Louis Dreyfus Energy Services (10%) and Shell Trading (US) Company (10%); and 2004 — Louis Dreyfus Energy Services (11%) and Shell Trading (US) Company (10%). All of these customers were purchasers of our oil and gas production. We estimate that in 2006 we provided subsea services to over 150 customers.

 

Our contracting services projects have historically been of shorter duration and are generally awarded shortly before mobilization. As a result, no significant backlog existed prior to 2006. In 2006, we entered into several long-term contracts, for certain of our Deepwater and Well Ops 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. We do not typically tender in the Engineering Procurement and Installation Contract (“EPIC”) market as other contractors do. For that reason, other contractors are more likely to be our customers and we serve as a contractor’s contractor.

 

COMPETITION

 

The marine contracting 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 competitors on the OCS include Global Industries, Ltd., Oceaneering International, Inc. and a number of smaller companies, some of which only operate a single vessel and often compete solely on price. For Deepwater projects, our principal competitors include Acergy, Subsea 7, and Technip-Coflexip.

 

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. Our primary oil and gas competitors include Newfield Exploration Company, ATP Oil & Gas Corp, W&T Offshore, Inc., Energy Partners, Ltd. and Mariner Energy, Inc. We also encounter significant competition for the acquisition of mature oil and gas properties. Our ability to acquire additional properties depends upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Competition includes TETRA Technologies, Inc. and Superior Energy Services, Inc. for Gulf of Mexico mature properties. 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 on development properties.

 

TRAINING, SAFETY AND QUALITY ASSURANCE

 

We have established a corporate culture in which EHS remains among the highest of priorities. Our corporate goal, based on the belief that all accidents can be prevented, is to provide an injury-free workplace by focusing on correct, safe behavior. Our EHS 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 EHS programs are among the best in the industry. We have introduced a company-wide effort to enhance and provide continual 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 of 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. To further this continual improvement effort, progressive auditing is done to continue improvement of our EHS management system. Results from this program were evident as our safety performance improved significantly from 2003 through 2006.

 

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, the U.S. Environmental Protection Agency, the MMS and the U.S. Customs Service, as well as private industry organizations such as the American Bureau of Shipping. 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 branch adheres 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.

 

We support and voluntarily comply with standards of the Association of Diving Contractors International. 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 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 taxes 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 MMS.

 

The MMS 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 $500,000 per producing lease. We have provided adequate financial assurance for our offshore leases as required by the MMS.

 

We acquire production rights to offshore mature oil and gas properties under federal oil and gas leases, which the MMS administers. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act, or OCSLA. These MMS directives are subject to change. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has issued regulations restricting the flaring or venting of natural gas and prohibiting the burning of liquid hydrocarbons without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. Finally, under certain circumstances, the MMS 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.

 

Under the OCSLA and the Federal Oil and Gas Royalty Management Act, MMS also administers oil and gas leases and 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 MMS.

 

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, or 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. 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. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended the NGPA to remove both price and non-price controls from natural gas sold in “first sales” no later than January 1, 1993.

 

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, 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. Changes in FERC rules and regulations may also affect the intrastate transportation of natural gas 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. 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. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material effect upon our capital expenditures, financial conditions, earnings or competitive position.

 

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, or 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 $500,000 or $600 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 MMS has promulgated regulations implementing these financial responsibility requirements for covered offshore facilities. Under the MMS 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 MMS 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 six 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 well as other assets we own or operate or which are owned or operated by either our customers or our sub-contractors.

 

Management believes that we are in compliance in all material respects with all 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.

 

EMPLOYEES

 

We rely on the high quality of our workforce. As of December 31, 2006, we had over 2,300 employees, nearly 980 of which were salaried personnel. Of the total employees, approximately 1,300 were employees of Cal Dive. As of December 31, 2006, we also contracted with third parties to utilize approximately 580 non-U.S. citizens to crew our foreign flag vessels. None of our employees belong to a union nor are employed pursuant to any collective bargaining agreement or any similar arrangement. We believe our relationship with our employees and foreign crew members is good.

 

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, 2006, and copies of our Quarterly Reports on Form 10-Q for 2006 and 2007 and any Current Reports on Form 8-K for 2006 and 2007, 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 SEC. 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.

 

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 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.

 

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, 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:

 

 

The level of offshore construction activity improved somewhat in 2004 with the trend continuing through 2006, following higher commodity prices from 2003 to 2006 and significant damage sustained to the Gulf of Mexico infrastructure in Hurricanes Katrina and Rita in 2005. We cannot assure you that activity levels will remain the same or increase. A sustained period of low drilling and production activity or the return of 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. We maintain such insurance protection as we deem prudent, including Jones Act employee coverage, which is the maritime equivalent of workers’ compensation, and hull insurance on our vessels. We cannot assure you that any such insurance will 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 and with the initial public offering of CDI, a greater percentage of our revenues may be from 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 our operating performance.

 

Our contracting business typically declines in winter, and bad weather in the Gulf or North Sea can adversely affect our operations.

 

Marine operations conducted in the Gulf 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.

 

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, and the performance of third parties such as equipment suppliers. These variations and risks inherent in the marine construction industry may result in our experiencing reduced profitability or losses on projects.

 

Delays or cost overruns in our construction projects could adversely affect our business or the expected cash flows from these projects upon completion may not be timely or as high as expected.

 

We currently have the following significant construction projects in our contracting services operations:

 

 

Although the construction contracts provide for delay penalties, these projects are subject to the risk of delay or cost overruns inherent in construction projects. These risks include, but are not limited to:

 

 

Significant delays could also have a material adverse effect on expected contract commitments for these projects and our future revenues and cash flow. We will not receive any material increase in revenue or cash flows from these assets until they are placed in service and customers enter into binding arrangements for the assets, which can potentially be several months after the construction or conversion projects are completed. Furthermore, we cannot assure you that customer demand for these assets will be as high as currently anticipated, and, as a result, our future cash flows may be adversely affected. In addition, new assets from third-parties may also enter the market in the future and compete with us.

 

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 & 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 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 depend on a number of additional factors, including commodity prices, market demand and the political, economic and regulatory climate.

 

Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

 

Natural gas and oil prices are volatile, which makes future revenue uncertain.

 

Our financial condition 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:

 

 

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 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 in order to hedge our exposure to price volatility, a dramatic decline in such prices could have a substantial and material effect on:

 

 

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 forward sold for future physical delivery a portion of our future production. This means that a portion of our production is sold at a fixed price as a shield against dramatic price declines that could occur in the market. In addition, we have entered into costless collar contracts related to some of our future oil and gas production. We may from time to time engage in other hedging activities that limit our upside potential from price increases. These sales activities may limit our benefit from dramatic price increases.

 

Estimates of our oil and gas reserves, future cash flows and abandonment costs may be significantly incorrect.

 

This Annual Report contains estimates of our proved oil and gas reserves and the estimated future net cash flows therefrom based upon reports for the years ended December 31, 2006 and 2005, audited by our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the Securities and Exchange Commission, as to oil and gas prices, drilling and operating expenses, capital expenditures, abandonment 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 expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially 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 Securities and Exchange Commission requirements, we base the estimated discounted future net cash flows from our proved reserves on prices 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.

 

Reserve replacement may not offset depletion.

 

Oil and gas properties are depleting assets. We replace reserves through acquisitions, exploration and exploitation of current properties. 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, 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, 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:

 

 

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

 

Government regulation may affect our ability to conduct operations, and the nature of our business exposes us to environmental liability.

 

Numerous federal and state regulations affect our oil and gas 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.

 

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.

 

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 well as other assets we own or operate or which are owned or operated by either our customers or our sub-contractors.

 

In addition, 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. Such environmental liability could substantially reduce our net income and could have a significant impact on our financial ability to carry out our oil and gas operations.

 

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 flows.

 

Risks Relating to General Corporate Matters

 

We have higher levels of indebtedness after the acquisition of Remington in 2006.

 

As of December 31, 2006, we have approximately $1.5 billion of indebtedness outstanding. The significant level of combined indebtedness may have an adverse effect on our future operations, including:

 

 

If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.

 

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 or the North Sea, 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 demands, political change and government regulations.

 

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, among other reasons, 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. We believe that our success and continued growth are also dependent upon our ability to attract and retain skilled personnel. We believe that our wage rates are competitive; however, unionization or a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in the wage rates we pay, or both. If either of these events occurs for any significant period of time, our revenues 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, and is expected to continue to place, 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.

 

We may need to change the manner in which we conduct our business in response to changes in government regulations.

 

Our subsea construction, intervention, inspection, maintenance and decommissioning operations and our oil and gas production from offshore properties, including decommissioning of such properties, are subject to and affected by various types of government regulation, including numerous federal, state and local environmental protection laws and regulations. These laws and regulations are becoming increasingly complex, stringent and expensive to comply with, and significant fines and penalties may be imposed for noncompliance. We cannot assure you that continued compliance with existing or future laws or regulations will not adversely affect our operations.

 

Certain provisions of our corporate documents and Minnesota law may discourage a third party from making a takeover proposal.

 

In addition to the 55,000 shares of preferred stock issued to Fletcher International, Ltd. under the First Amended and Restated Agreement dated January 17, 2003, but effective as of December 31, 2002, by and between Helix and Fletcher International, Ltd., our board of directors has the authority, without any action by our shareholders, to fix the rights and preferences on up to 4,945,000 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 contracts with most of our senior officers that require cash payments in the event of a “change of control.” Any or all of the provisions or factors described above may have the effect of discouraging 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.

 

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:

 

 

In addition, laws and policies of the United States affecting foreign trade and taxation may also adversely affect our international operations.

 

Our ability to market oil and natural gas discovered or produced in any future foreign operations, and the price we could obtain for such production, depends on many factors beyond our control, including:

 

 

Pipeline and processing facilities do not exist in certain areas of exploration and, therefore, any actual sales of our production could be delayed for extended periods of time until such facilities are constructed.

 

As the initial public offering of CDI common stock was completed, in the future, we may not have the same access to services and equipment, as we had historically.

 

Although we have made arrangements to retain access to the services and equipment of CDI through certain inter-company agreements, it is possible that we will not have the same access to those services and equipment as we had historically, and as our ownership in CDI decreases over time, our access to such equipment and services could be further diminished.

 

None.

 

We own a fleet of 33 vessels (one of which was held-for-sale at December 31, 2006 and sold in January 2007) and 31 ROVs and trenchers. We also lease one vessel. We believe that the market in the Gulf of Mexico requires specially designed and/or equipped vessels to competitively deliver subsea construction and well operations services. Eleven of our vessels have DP capabilities specifically designed to respond to the deepwater market requirements. Fifteen of our vessels (thirteen of which are based in the Gulf of Mexico) have the capability to provide saturation diving services.

 

Divestitures in 2006

 

In December 2006, we contributed the assets of our Shelf Contracting segment into CDI, our then wholly owned subsidiary. CDI subsequently completed an initial public offering selling 22,173,000 shares of its common stock, which, together with shares issued to CDI employees immediately after the offering, reduced our ownership of CDI to 73.0%. CDI received net proceeds of $264.4 million from its initial public offering. All of the net proceeds were distributed to us as a dividend. In connection with the offering, CDI entered into a $250 million revolving credit facility. In December 2006, Cal Dive borrowed $201 million under the facility and distributed $200 million of the proceeds to us as a dividend. See “— Note 3 — Initial Public Offering of Cal Dive International, Inc.” in Item 8 for additional information.

 

Related to the Acergy acquisition, we entered into a consent order with the U.S. Department of Justice pursuant to which we agreed to divest three assets: the Carrier, the Defender and a portable saturation diving system acquired from Torch. As a result, these vessels were classified as held for sale at December 31, 2005. In 2006, we sold the portable saturation diving system and the Defender. As of December 31, 2006, the Carrier remained classified as held for sale. In January 2007, the Carrier was sold to an unrelated third-party. No gains or losses were recognized related to the sale.

 

Acquisitions in 2006

 

In January 2006, our wholly owned subsidiary, Vulcan Marine Technology LLC, acquired the Caesar (formerly known as the Baron), a four year old mono-hull vessel originally built for the cable lay market. The vessel was under charter to a third-party until mid January 2007. After the completion of the charter, the vessel was in transit to a shipyard in China where we plan to convert the vessel into a deepwater pipelay asset. The vessel is 485 feet long and already has a state-of-the-art, class 2, dynamic positioning system. The conversion program will primarily involve the installation of a conventional ‘S’ lay pipelay system together with a main crane and a significant upgrade to the accommodation capability. A conversion team has already been assembled with a base at Rotterdam, the Netherlands, and the vessel is likely to enter service during the second half of 2007. The estimated cost to acquire and convert the vessel will be approximately $137.5 million. We have entered into an agreement with the third party currently leasing the vessel, whereby the third party has an option to purchase up to 49% of Vulcan for consideration totaling the proportionate share of the cost of the vessel plus the actual cost of conversion (conversion cost is estimated to be $110.0 million). The third party must make all contributions to Vulcan on or before March 31, 2007.

 

In January 2006, the DLB 801 was acquired from Acergy. Subsequent to our purchase of the DLB 801, we sold a 50% interest in the vessel in January 2006 for approximately $19.0 million. The vessel is currently under a 10-year charter lease agreement with the purchaser of the 50% interest, in which the purchaser has an option to purchase the remaining 50% interest in the vessel beginning in January 2009. This lease was accounted for as an operating lease. In March 2006, we also acquired the Kestrel from Acergy.

 

On July 1, 2006, we acquired 100% of Remington, an independent oil and gas exploration and production company headquartered in Dallas, Texas, with operations concentrated in the onshore and offshore regions of the Gulf Coast, for approximately $1.4 billion in cash and stock and the assumption of $349.6 million of liabilities. The acquisition of Remington increased our oil and gas properties by approximately $860 million.

 

In addition, in July 2006, we acquired the business of Singapore-based Fraser Diving International Ltd for an aggregate purchase price of approximately $29.3 million, subject to post-closing adjustments, and the assumption of $2.2 million of liabilities. FDI owns six portable saturation diving systems and 15 surface diving systems that operate primarily in Southeast Asia, the Middle East, Australia and the Mediterranean. Included in the purchase price is a payment of $2.5 million made in December 2005 to FDI for the purchase of one of the portable saturation diving systems. The acquisition was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values. All of the assets acquired from FDI are included in our Shelf Contracting segment.

 

In August 2006, we acquired a 100% working interest in the Typhoon oil field (Green Canyon Blocks 236/237), the Boris oil field (Green Canyon Block 282) and the Little Burn oil field (Green Canyon Block 238) for the assumption of certain decommissioning liabilities. We have received suspension of production (“SOP”) approval from the MMS. We will also have farm-in rights on five near by blocks where three prospects have been identified in the Typhoon mini-basin. Following the acquisition of the Typhoon field and MMS approval, we renamed the field Phoenix. We expect to deploy a minimal floating production system in mid-2008 in the Phoenix field (see below).

 

Further, in October 2006, we, along with Kommandor RØMØ A/S (“Kommandor RØMØ”), a Danish corporation, formed Kommandor, LLC (“Kommandor”), a Delaware limited liability company, to convert a ferry vessel into a dynamically-positioned minimal floating production system (see “— Production Facilities” below). Kommandor qualified as a variable interest entity (“VIE”) under FASB Interpretation No. 46 Consolidation of Variable Interest Entities (“FIN 46”). We are the primary beneficiary of Kommandor. As a result, we have consolidated the results of Kommandor at December 31, 2006.

 

Also in October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (“Seatrac”) for total consideration of approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1 million paid to existing shareholders and $3.4 million for subscription of new Seatrac shares (see “Note 6 — Other Acquisitions” in Item 8. Financial Statements and Supplementary Data for a detailed discussion of Seatrac). We changed the name of the entity to Well Ops SEA Pty Ltd.

 

In December 2006, we acquired a 100% working interest in the Camelot oil field in the North Sea for the assumption of certain decommissioning liabilities totaling approximately $7.6 million. At December 31, 2006, Camelot had proved reserves of approximately 24 Bcfe. We have commenced existing field rejuvenation and expect first production in 2007. It is our intent to sell down to a 50% working interest prior to additional drilling or other large capital investments being made in the Camelot field area.

OUR VESSELS

 

Listing of Vessels, Barges and ROVs Related to Contracting Services Operations (1)

 

 

 

 

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, 2006, 2005 and 2004:

 

 

We incur routine drydock, inspection, maintenance and repair costs pursuant to Coast Guard regulations and 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 in other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and dive support vessels. The Q4000 is subject to a mortgage that secures the MARAD financing guarantees as described in Item 8. Financial Statements and Supplementary Data “— Note 10 — Long-term Debt.”

 

SUMMARY OF NATURAL GAS AND OIL RESERVE DATA

 

The table below sets forth information, as of December 31, 2006, with respect to estimates of net proved reserves, prepared in accordance with guidance established by the SEC. Our U.S. reserve estimates at December 31, 2006 have been audited by Huddleston & Co., Inc., independent petroleum engineers (83% of our most significant U.S. proved reserves on a discounted future net revenue basis). 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.

 

 

For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see “Item 8. Financial Statements and Supplementary Data “— Note 20 — Supplemental Oil and Gas Disclosures.”

 

Production, Price and Cost Data

 

Production, price and cost data for our oil and gas operations in the United States are as follows:

 

 

As we acquired Camelot in December 2006 (which was not then producing), we had no oil and gas production in the United Kingdom in 2006.

 

Productive Wells

 

The number of productive oil and gas wells in which we held interest as of December 31, 2006 is as follows:

 

 

Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. 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 as of December 31, 2006. Included in non-producing wells are productive wells awaiting additional action, pipeline connections or shut-in for various reasons.

 

 

Developed and Undeveloped Acreage

 

The developed and undeveloped acreage (including both leases and concessions) that we held at December 31, 2006 is as follows:

 

 

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 so 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 (acreage):

 

 

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, 2006, 2005 and 2004:

 

 

As we acquired Camelot in December 2006, no wells were drilled in the United Kingdom in 2006.

 

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.

 

At December 31, 2006, our oil and gas operations were drilling 2 gross (0.6 net) development wells and 6 gross (4 net) exploration wells, and 0.4 net suspended exploratory wells. These wells are located in the Gulf of Mexico. The drilling cost to us for these wells will be approximately $104.2 million if all are dry and approximately $163.4 million if all are completed as producing wells.

 

PRODUCTION FACILITIES

 

Through our interest in Deepwater Gateway, L.L.C., a limited liability company in which Enterprise Products Partners L.P. is the other member, we own a 50% interest in the Marco Polo TLP, which was installed on Green Canyon Block 608 in 4,300 feet of water. Deepwater Gateway, L.L.C. 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. Anadarko required 50,000 barrels of oil per day and 150 million feet per day of processing capacity for Marco Polo.  The Marco Polo TLP was designed to process 120,000 barrels of oil per day and 300 million cubic feet of gas per day and payload with space for up to six subsea tie backs.

 

We also own a 20% interest in Independence Hub, LLC, an affiliate of Enterprise Products Partners L.P., that will own the “Independence Hub” platform, a 105 foot deep draft, semi-submersible platform to be located in Mississippi Canyon block 920 in a water depth of 8,000 feet that will serve as a regional hub for natural gas production from multiple ultra-Deepwater fields in the previously untapped eastern Gulf of Mexico. Installation of

the platform is scheduled for the first quarter of 2007 and first production is expected in mid-2007. The Independence Hub facility will be capable of processing 1 billion cubic feet (bcf) per day of gas.

 

We own a 20% interest in the Gunnison truss spar facility, together with the operator Kerr-McGee Oil & Gas Corporation, which owns a 50% interest, and Nexen, Inc., which owns the remaining 30% interest. The Gunnison spar, which is moored in 3,150 feet of water and located on Garden Banks Block 668, has daily production capacity of 40,000 barrels of oil and 200 million cubic feet of gas. This facility is designed with excess capacity to accommodate production from satellite prospects in the area.

 

Further, in October 2006, we invested $15 million for a 50% interest in Kommandor to convert a ferry vessel into a dynamically-positioned minimal floating production system. Upon completion of the initial conversion, this vessel will be leased under a bareboat charter to us for further conversion and subsequent use as a floating production system in the Deepwater Gulf of Mexico, initially for the Phoenix field. Conversion of the vessel is expected to be completed in two phases. The first phase is expected to be completed by the end of 2007 for approximately $60 million. The second phase of the conversion is expected to be completed by mid-2008. Estimated cost of conversion for the second phase is approximately $100 million, of which we expect to fund 100%.

FACILITIES

 

Our corporate headquarters are located at 400 N. Sam Houston Parkway E., Suite 400, Houston, Texas. Our primary subsea and marine services operations are based in Port of Iberia, Louisiana. We own the Aberdeen (Dyce), Scotland facility. All of our other facilities are leased.

 

Properties and Facilities Summary

 

 

 

Insurance and Litigation

 

Our operations are subject to the inherent risks of offshore marine activity, including accidents resulting in personal injury and the loss of life or property, environmental mishaps, mechanical failures, fires and collisions. We insure against these risks at levels consistent with industry standards. We also carry workers’ compensation, maritime employer’s liability, general liability and other insurance customary in our business. All insurance is carried at levels of coverage and deductibles we consider financially prudent. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could occur, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. Although there can be no assurance that the amount of insurance we carry is sufficient to protect us fully in all events, or that such insurance will continue to be available at current levels of cost or coverage, we believe that our insurance protection is adequate for our business operations. A successful liability claim for which we are underinsured or uninsured could have a material adverse effect on our business.

 

We are involved in various legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act as a result of alleged negligence. In addition, we from time to time incur other claims, such as contract disputes, in the normal course of business. In that regard, in 1998, one of our subsidiaries, Cal Dive Offshore Ltd (“CDO”), entered into a subcontract with Seacore Marine Contractors Limited (“Seacore”) to provide a vessel to Seacore for use in performing a contract between Seacore and Coflexip Stena Offshore Newfoundland (“Coflexip”) in Canada. Due to various difficulties, that contract was terminated and an arbitration to recover damages was commenced. We were not a party to that arbitration. A liability finding was made by the arbitrator against Seacore and in favor of Coflexip. Seacore and Coflexip settled this matter with Seacore paying Coflexip CAD$6.95 million. Seacore then initiated an arbitration proceeding against CDO seeking payment of that amount, and subsequently commenced a lawsuit against us seeking the same recovery. Recently we have settled this litigation and arbitration, with us making a payment to Seacore in the amount of CAD$825,000 (or approximately $703,000), and the parties fully and finally releasing each other from all claims pertaining the matter.

 

On December 2, 2005, we received an order from the U.S. Department of the Interior Minerals Management Service (“MMS”) that the price threshold for both oil and gas was exceeded for 2004 production and that royalties are due on such production notwithstanding the provisions of the Deep Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalty on certain federal leases. Our only oil and gas leases affected by this dispute are Garden Banks Blocks 667, 668 and 669 (“Gunnison”). On May 2, 2006, the MMS issued another order that superseded the December 2005 order, and claimed that royalties on gas production are due for 2003 in addition to oil and gas production in 2004. The May 2006 Order also seeks interest on all royalties allegedly due. We filed a timely notice of appeal with respect to both the December 2005 Order and the May 2006 Order. Other operators in the Deep Water Gulf of Mexico who have received notices similar to ours are seeking royalty relief under the DWRRA, including Kerr-McGee Oil and Gas Corporation (“Kerr-McGee”), the operator of Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the enforceability of price thresholds in certain deepwater Gulf of Mexico Leases, such as ours. We do not anticipate that the MMS director will issue decisions in our or the other companies’ administrative appeals until the Kerr-McGee litigation has been resolved. As a result of this dispute, we have recorded reserves for the disputed royalties (and any other royalties that may be claimed for production during 2005 and 2006) plus interest at 5% for our portion of the Gunnison related MMS claim. The total reserved amount at December 31, 2006 was approximately $42.6 million. At this time, it is not anticipated that any penalties would be assessed even if we are unsuccessful in our appeal.

 

Although the above discussed matters may have the potential for additional liability and may have an impact on our consolidated financial results for a particular reporting period, we believe that the outcome of all such matters and proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

 

None.

 

The executive officers of Helix are as follows:

 

 

Owen Kratz is Executive Chairman and the principal executive officer of Helix. He was appointed Chairman in May 1998 and served as our Chief Executive Officer from April 1997 until October 2006, at which time he was appointed Executive Chairman. Mr. Kratz served as President from 1993 until February 1999, and has been a Director since 1990. He served as Chief Operating Officer from 1990 through 1997. Mr. Kratz joined Helix in 1984 and has held various offshore positions, including saturation diving supervisor, and has had management responsibility for client relations, marketing and estimating. Mr. Kratz has a Bachelor of Science degree in Biology and Chemistry from State University of New York.

 

Martin R. Ferron has served on our Board of Directors since September 1998. Mr. Ferron became President in February 1999 and was appointed Chief Executive Officer in October 2006. Mr. Ferron served as Chief Operating Officer from January 1998 until September 2005. Mr. Ferron has over 25 years of experience in the oilfield industry, including seven in senior management positions with the international operations of McDermott and Oceaneering. Mr. Ferron has a civil engineering degree, a master’s degree in marine technology, an MBA and is a chartered civil engineer.

 

Bart H. Heijermans became Executive Vice President and Chief Operating Officer of Helix in September 2005. Prior to joining Helix, Mr. Heijermans worked as Senior Vice President Offshore and Gas Storage for Enterprise Products Partners, L.P. from 2004 to 2005 and previously from 1998 to 2004 was Vice President Commercial and Vice President Operations and Engineering for GulfTerra Energy Partners, L.P. Before his employment with GulfTerra, Mr. Heijermans held various positions with Royal Dutch Shell in the United States, the United Kingdom and the Netherlands. Mr. Heijermans received a Master of Science degree in Civil and Structural Engineering from the University of Delft, the Netherlands and is a graduate of the Harvard Business School Executive Program.

 

Robert P. Murphy was elected as Executive Vice President — Oil & Gas of Helix on February 28, 2007, and as President and Chief Operating Officer of Helix Oil & Gas, Inc., a wholly owned subsidiary, on November 29, 2006. Mr. Murphy joined Helix on July 1, 2006 when Helix acquired Remington Oil & Gas Corporation, where Mr. Murphy served as President, Chief Operating Officer and was on the Board of Directors. Prior to joining Remington, Mr. Murphy was Vice President — Exploration of Cairn Energy USA, Inc, of which company Mr. Murphy also served on the Board of Directors. Mr. Murphy received a Bachelor of Science degree in Geology from The University of Texas at Austin, and has a Master of Science in Geosciences from the University of Texas at Dallas.

 

A. Wade Pursell was elected as Executive Vice President and Chief Financial Officer on February 28, 2007, and prior to that, held the office of Senior Vice President and Chief Financial Officer, to which he was appointed in October 2000. Mr. Pursell oversees the finance, treasury, accounting, tax, information technology, administration and corporate planning functions. He joined Helix in May 1997, as Vice President — Finance and Chief Accounting Officer. From 1988 through 1997 he was with Arthur Andersen LLP, lastly as an Experienced Manager specializing in the offshore services industry. Mr. Pursell received a Bachelor of Science degree from the University of Central Arkansas.

 

Alisa B. Johnson became Senior Vice President, General Counsel and Secretary of Helix in September 2006. Ms. Johnson has been involved with the energy industry for over 15 years. Prior to joining Helix, Ms. Johnson worked for Dynegy Inc. for nine years, at which company she held various legal positions, 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 from Rice University and her law degree from the University of Houston.

 

Lloyd A. Hajdik joined the Company in December 2003 as Vice President — Corporate Controller and became Chief Accounting Officer in February 2004. From January 2002 to November 2003 he was Assistant Corporate Controller for Houston-based NL Industries, Inc. Prior to NL Industries, Mr. Hajdik served as Senior Manager of SEC Reporting and Accounting Services for Compaq Computer Corporation from 2000 to 2002, and as Controller for Halliburton’s Baroid Drilling Fluids and Zonal Isolation product service lines from 1997 to 2000. Mr. Hajdik served as Controller for Engineering Services for Cliffs Drilling Company from 1995 to 1997 and was with Ernst & Young in the audit practice from 1989 to 1995. Mr. Hajdik graduated from Texas State University — San Marcos (formerly Southwest 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.

 

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HLX.” Prior to July 18, 2006, our common stock was quoted on the NASDAQ under the symbol “HELX.” Prior to March 6, 2006, our common stock traded under the symbol “CDIS” on the NASDAQ. The following table sets forth, for the periods indicated, the high and low closing sale prices per share of our common stock:

 

 

 

 

On February 28, 2007, the closing sale price of our common stock on the NYSE was $33.49 per share. As of February 22, 2007, there were an estimated 313 registered shareholders (approximately 56,179 beneficial owners) 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, 2001 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 (the “Peer Group”) consisting of the following companies: Global Industries, Ltd., Acergy US, Inc., Oceaneering International, Inc., Technip-Coflexip, Superior Energy Services, Inc., TETRA Technologies, Inc., Subsea 7, Newfield Exploration Company, ATP Oil & Gas Corp, W&T Offshore, Inc., Energy Partners, Ltd., and Mariner Energy, 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, 2006 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, 2001 in our common stock at the closing price on that date price and on December 31, 2001 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 — 154.2%; the Peer Group — 247.4%; the OSX — 132.2%; and S&P 500- 31.1%. 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

 

 

 

Source: Bloomberg

 

Issuer Purchases of Equity Securities

 

 

 

 

 

The financial data presented below for each of the five years ended December 31, 2006, 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 Form 10-K.

 

 

 

 

 

 

 

The following management discussion and analysis should be read in conjunction with our historical consolidated financial statements and their notes included elsewhere in this report. This discussion contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under “Risk Factors” and elsewhere in this report.

 

Executive Summary

 

Our Business

 

We are an international offshore energy company that provides development solutions and other key services to the open 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 (F&D) costs, relative to industry norms.

 

Industry Overview and Major Influences

 

The offshore oil and gas industry originated in the early 1950s as producers began to explore and develop the new frontier of offshore fields. The industry has grown significantly since the 1970s with service providers taking on greater roles on behalf of the producers. Industry standards were established during this period largely in response to the emergence of the North Sea as a major province leading the way into a new hostile frontier. The methodology of these standards was driven by the requirement of mitigating the risk of developing relatively large reservoirs in a then challenging environment. These standards are still largely adhered to today for all developments even if they are small and the frontier is more understood. There are factors we believe will influence the industry in the coming years: (1) Increasing world demand for oil and natural gas; (2) global production rates peaking; (3) globalization of the natural gas market; (4) increasing number of mature and small reservoirs; (5) increasing ratio of contribution to global production from marginal fields; (6) increasing offshore activity; and (7) increasing number of subsea developments.

 

Our business is substantially dependent upon the condition of the oil and natural gas industry and, in particular, the willingness of oil and natural gas companies to make capital expenditures for offshore exploration, drilling and production operations. The level of capital expenditure generally depends on the prevailing views of future oil and natural gas prices, which are influenced by numerous factors, including but not limited to:

 

 

 

Activity Summary

 

Over the last few years we continued to evolve the Helix model by completing a variety of transactions and events which have had, and we believe will continue to have, significant impacts on our results of operations and financial condition. In 2005, we substantially increased the size of our Shelf Contracting fleet and Deepwater pipelay fleet through the acquisition of assets from Torch and Acergy for a combined purchase price of $210.2 million. We also acquired a significant mature property package on the Gulf of Mexico OCS from Murphy Oil Corporation for $163.5 million cash and assumption of abandonment liability of $32 million. Finally, we established our Reservoir and Well Tech Services group through the acquisition of Helix Energy Limited (“Helix RDS”) for $32.7 million. In 2006, we acquired Remington, an exploration, development and production company, for approximately $1.4 billion in cash and stock and the assumption of $349.6 million of liabilities. We changed our name from Cal Dive International, Inc. to Helix Energy Solutions Group, Inc., leaving the “Cal Dive” name in our diving subsidiary, and in December 2006 completed a carve-out IPO of that company selling a 26.5% stake receiving pre-tax net proceeds of $264.4 million from CDI and a pre-tax dividend of $200 million from CDI’s revolver. We acquired the Caesar, a 485 foot cable lay vessel which we intend to convert into a Deepwater pipelay asset (total acquisition plus estimated conversion cost is $137.5 million). We also acquired a 100% interest in the Phoenix field (formerly known as Typhoon) where we expect to deploy a minimal floating production system in mid-2008. We also expanded our subsea well intervention services in Australia through the acquisition of 58% of Seatrac. Finally, we moved our stock listing from Nasdaq (HELX) to the New York Stock Exchange (HLX) in July 2006.

 

In February 2007, we announced an update on drilling activity at our 100% owned Noonan prospect on Garden Banks Block 506 in 2,700 feet of water. Since operations commenced in October 2006, we have completed the drilling of an exploratory well and two appraisal sidetracks. Formation evaluation from wireline logs, pressure analysis and sidewall cores have successfully delineated our reservoir for completion of the well.

 

Results of Operations

 

Our operations are conducted through the following lines of businesses: contracting services operations and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS 131. As a result, our reportable segments consist of the following: Contracting Services (formerly known as Deepwater Contracting), Shelf Contracting, Oil and Gas (formerly known as Oil and Gas Production) and Production Facilities. Contracting Services operations include services such as deepwater pipelay, well operations, robotics and reservoir and well tech services. Shelf Contracting operations consist of assets deployed primarily for diving-related activities and shallow water construction. See Item 8. Financial Statements and Supplementary Data “— Note 3 — Initial Public Offering of Cal Dive International, Inc.” for discussion of

initial public offering of CDI common stock (represented by the Shelf Contracting segment). All material intercompany transactions between the segments have been eliminated in our consolidated results of operations.

 

Comparison of Years Ended 2006 and 2005

 

The following table details various financial and operational highlights for the periods presented: