Helix Energy Solutions 10-K 2008
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission File Number 001-32936
HELIX ENERGY SOLUTIONS GROUP, INC.
(Registrants telephone number, including area code)
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 registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
(Do not check if a smaller
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 based on the last reported sales price of the Registrants Common Stock on June 30, 2007 was approximately $3.4 billion.
The number of shares of the registrants Common Stock outstanding as of February 26, 2008 was 91,674,430.
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 6, 2008, are incorporated by reference into Part III hereof.
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 (Exchange Act). 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 19 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.
Helix Energy Solutions Group, Inc. (Helix) is an international offshore energy company, incorporated in the state of Minnesota in 1979, that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels and offshore equipment that when applied with our methodologies reduce finding and development (F&D) costs and cover the complete lifecycle of an offshore oil and gas field. Our Oil and Gas segment engages in prospect generation, exploration, development and production activities. We operate primarily in the Gulf of Mexico, North Sea, Asia Pacific and Middle East regions. 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 Chief Executive Officer (formerly Executive Chairman) submitted the annual CEO certification to the New York Stock Exchange as required under the NYSE listed Company Manual in April 2007. 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.
We provide offshore services and methodologies that we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. By marginal, we mean reservoirs that are no longer wanted by major operators or are too small to be material to them. Our life of field services are organized in five disciplines: construction, well operations, drilling, production facilities, and reservoir and well technology services. 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 No. 131): Contracting Services (which includes deepwater construction, well operations, reservoir and well technology services and in the future, drilling), Shelf Contracting and Production Facilities.
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, North Sea and Asia Pacific regions. Our deepwater construction services include pipelay and robotics in water depth of more than 1,000 feet. We also provide construction services periodically from our well intervention vessels. We perform traditional subsea services, including air and saturation diving, salvage work and shallow water pipelay on the Outer Continental Shelf (OCS) of the Gulf of Mexico in water depths up to 1,000 feet through Cal Dive, a majority-owned subsidiary in which we currently own 58.5%. We have consolidated the financial results of Cal Dive as of December 31, 2007. Cal Dive stock publicly trades on the New York Stock Exchange under the ticker symbol DVR.
We believe we are the global leader in rig alternative subsea well intervention. We engineer, manage and conduct well construction, intervention and decommissioning operations in water depths ranging from 200 to 10,000 feet. With the increased demand for these services caused by the growing number of subsea tree
installations, coupled with the shortfall in Deepwater rig availability, we are constructing a newbuild North Sea vessel and have expanded geographically in Australia and Asia with the acquisition of Seatrac Pty Ltd. (Seatrac), an established Australian well operations company now called Well Ops SEA Pty Limited (WOSEA).
We own interests in certain production facilities in hub locations where there is potential for significant subsea tieback activity. Ownership of production facilities enables us to earn a transmission company type return through tariff charges while providing construction work for our vessels. We own a 50% interest in the Marco Polo tension leg platform (TLP), which was installed in 4,300 feet of water in the Gulf of Mexico, through Deepwater Gateway, L.L.C. (Deepwater Gateway). We also own a 20% interest in Independence Hub, L.L.C. (Independence), an affiliate of Enterprise Products Partners L.P. Independence owns the Independence Hub platform, a 105-foot deep draft, semi-submersible platform, which was installed during 2007. The platform is located in a water depth of 8,000 feet, which serves as a regional hub for up to 1 billion cubic feet of natural gas production per day from multiple ultra-deepwater fields in the previously untapped eastern Gulf of Mexico. Finally, through a consolidated 50% owned entity, we are currently converting a vessel into a floating production unit for use on our Phoenix field in the Gulf of Mexico.
In 2005, we acquired Helix Energy Limited, the largest outsource provider of sub-surface technology skills in the North Sea. With a technical staff of over 90 employees, we have the resources to provide valuable well enhancement services, which typically increase production or extend the life of a reservoir, to our own oil and natural gas projects as well as to our clients. Each team we assign to a specific client comprises a diverse set of skills, including reservoir engineering, geology, modeling, flow assurance, completions, well design and production enhancement. With offices in Aberdeen, Perth, London, Kuala Lumpur and Perth, we have an established market presence in regions that we have identified as strategically important to future growth.
Contract drilling is a service we have not historically provided but have been contemplating since the construction of our Q4000 vessel over six years ago. Dayrates for deepwater drilling rigs have increased dramatically in recent years based on the significant oil and natural gas reserves located in deepwater regions and limited availability of rigs capable of drilling such depths. As a result, the drilling and completion cost of a subsea development can be as much as 50% of the total F&D costs. We are currently adding drilling capability to the Q4000, a project scheduled for completion in the second quarter of 2008. The type of drilling intended for this vessel 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 will allow us to drill most of our own deepwater prospects and support the exploration and appraisal efforts of our clients. We expect approval from the MMS for cased well services including completions in 2008 and approval for drilling once we have satisfied MMS requirements.
We formed our oil and gas operations in 1992 to provide a more efficient solution to offshore abandonment, to expand the off-season asset utilization of our contracting services business and to achieve incremental returns to our contracting services. 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. In July 2006, we acquired Remington Oil and Gas Corporation (Remington), an exploration, development and production company with operations primarily in the Gulf of Mexico. This acquisition has led to the assembly of services that allow us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment. We believe that owning controlling interests in reservoirs, particularly in deepwater, accomplishes the following:
As of December 31, 2007 we had 677 Bcfe of proved reserves with 95% of that located in the Gulf of Mexico.
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. We seek to maximize profitability by lowering F&D costs, reducing development time, operating our fields more effectively, and extending the reservoir life through well exploitation operations. Our reservoir engineering and geophysical expertise, along with our access to contracting services assets that can positively impact development costs, have made us a preferred partner for many other oil and gas companies in offshore development projects.
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 19 Business Segment Information. Within Contracting Services for financial reporting purposes, we have disclosed separately the financial information for Shelf Contracting and Production Facilities.
Demand for our contracting services operations is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, drilling and production operations. Generally, during periods of high commodity prices, oil and gas producers increase spending on our services in an effort to develop new reservoirs and enhance production from existing wells. The performance of our oil and gas operations is largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and excess capacity, geopolitical issues, weather and several other factors.
We believe that the long-term industry fundamentals are positive based on the following factors: (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, particularly in Deepwater; 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) through (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 and new reservoirs in which we have an equity stake.
Our primary goal is to provide services and methodologies to the industry which we believe are critical to finding and developing offshore reservoirs and maximizing the economics from marginal fields. A secondary 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 reduction in F&D costs. Meeting these objectives 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 Expansion of Contracting Services Capabilities. We will focus on providing offshore services that deliver the highest financial return to us. We will make strategic investments in capital projects that expand our services capabilities or add capacity to existing services in our key operating regions. Our capital investments have included adding offshore drilling capability to our Q4000 vessel, converting a vessel into a dynamically positioned floating production unit (Helix Producer I), converting a former dynamically positioned cable lay vessel into a deepwater pipelay vessel (the Caesar), and constructing the Well Enhancer vessel with greater well servicing capabilities in the North Sea.
Monetize Oil and Gas Reserves and Non-Core Assets. We intend to sell down interests in oil and gas reserves once value has been created via prospect generation, discovery and/or development engineering. Through this
approach we seek to lower reservoir and commodity risk, lower capital expenditures and increase third party contracting services profits.
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. Our interest in CDI was further reduced to 58.5% through CDIs acquisition in December 2007 of Horizon Offshore, Inc. (Horizon). See Item 8. Financial Statements and Supplementary Data Note 5 Acquisition of Horizon Offshore, Inc. We believe the Shelf Contracting segment is better positioned for growth as a separately traded entity.
Generate Prospects and Focus Exploration Drilling on Select Deepwater Prospects. We will continue to generate prospects and drill in areas where we believe our contracting services assets can be utilized and incremental returns will be achieved through control of and application of our development services and methodologies. To minimize our F&D costs, we intend to utilize the Q4000 for most of our deepwater drilling needs after the drilling upgrade is completed and regulatory approval has been obtained. Additionally, we plan to seek partners on these prospects to enhance financial results on the drilling and development work as well as to mitigate risk.
Continue 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 our ability to convert proved undeveloped reserves (PUD) and proved developed non-producing reserves (PDNP) into producing assets through successful exploitation drilling and well work. As of December 31, 2007, we had 67% of our proved reserves, or approximately 453 Bcfe, in the PUD category. We will focus on cost effectively developing these reserves to generate oil and gas production, or alternatively, selling full or partial interests in them to fund our growth initiatives and/or retire outstanding debt.
International Expansion of the Business Model. Based on attractive opportunities outside the Gulf of Mexico, we will continue to export our unique Gulf of Mexico business model to international offshore regions. We regard the North Sea and certain offshore areas of Southeast Asia as the primary regional targets for expansion. We have built a strong service presence in the North Sea and in December 2006 acquired our first mature oil and gas property in that area. In the Asia Pacific region, we completed two important service acquisitions in 2006 and will seek to grow our business there in a measured way over the near term.
Defined below are certain terms helpful to understanding our business:
Bcfe: One billion cubic feet equivalent, with one barrel of oil being equivalent to six thousand cubic feet of natural gas.
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, remotely operated vehicles (ROV) 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 the failure of one DP system; required for vessels which support both manned diving and robotics and for those working in close proximity to platforms. DP-2 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 end of the economic life of an oil field, including installation, inspection, maintenance, repair, contract operations, well intervention, recompletion and abandonment.
MBbl: When describing oil or other natural gas liquid, 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.
Mcf: When describing natural gas, refers to 1 thousand cubic feet.
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), Oceaneering International, Inc. (NYSE: OII), Cameron International Corporation (NYSE: CAM), Pride International, Inc. (NYSE: PDE), Oil States International, Inc. (NYSE: OIS), Grant Prideco, Inc. (NYSE: GRP), Rowan Companies, Inc. (NYSE: RDC), Complete Production Services, Inc. (NYSE: CPX), and Tidewater Inc. (NYSE: TDW).
Oil and Gas: Defined in this Annual Report as comprising 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 Developed Reserves: Reserves that geological and engineering data indicate with reasonable certainty to be recoverable today, or in the near future, with current technology and under current economic conditions.
Proved Undeveloped Reserves (PUD): Proved undeveloped oil and gas reserves that are expected to be recovered from a new well on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Remotely Operated Vehicle (ROV): Robotic vehicles used to complement, support and increase the efficiency of diving and subsea operations and for tasks beyond the capability of manned diving operations.
ROVDrill: ROV deployed coring system developed to take advantage of existing ROV technology. The coring package, deployed with the ROV system, is capable of taking cores from the seafloor in water depths up to 3000m. Because the system operates from the seafloor there is no need for surface drilling strings and the larger support spreads required for conventional coring.
Saturation Diving: Saturation diving, required for work in water depths between 200 and 1,000 feet, involves divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site.
Spar: Floating production facility anchored to the sea bed with catenary mooring lines.
Spot Market: Prevalent market for subsea contracting in the Gulf of Mexico, characterized by projects that are generally short in duration and often on a turnkey basis. These projects often require constant rescheduling and the availability or interchangeability of multiple vessels.
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 vessels ability to transport and fabricate hardware, supplies and equipment necessary to complete subsea projects.
Tension Leg Platform (TLP): A floating production facility anchored to the seabed with tendons.
Trencher or Trencher System: A subsea robotics system capable of providing post lay trenching, inspection and burial (PLIB) and maintenance of submarine cables and flowlines in water depths of 30 to 7,200 feet across a range of seabed and environmental conditions.
Ultra-Deepwater: Water depths beyond 4,000 feet.
Working Interest: The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
We provide a full range of contracting services primarily in the Gulf of Mexico, North Sea, Asia Pacific and Middle East regions in both the shallow water and deepwater. Our services include:
We provide offshore services and methodologies that we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. Those life of field services are organized in five disciplines: reservoir and well technology services, drilling, production facilities, construction and well operations. As of December 31, 2007, our contracting services operations had backlog of approximately $1.1 billion, of which approximately $630 million was expected to be completed in 2008.
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 8 inch) and umbilicals. The Express, which was acquired in 2005, is a 502 foot DP-2 vessel also capable of laying rigid and flexible pipe (up to 14 inch) 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 has a state-of-the-art DP-2 system. We are currently converting this vessel to a deepwater pipelay asset capable of laying rigid pipe up to 42 inch in diameter. The total estimated cost to acquire and convert the vessel is $172.5 million and the conversion is expected to be completed in third quarter 2008. We also periodically provide construction services from our well intervention vessels, Seawell and Q4000.
We operate ROVs, trenchers and ROV Drills 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 of Mexico and internationally. Our 35 ROVs and four trencher systems operate in three regions: the Americas, Europe/West Africa and Asia Pacific. We are in the process of building a new 2,000 HP trencher and a portable reeled pipelay system for the installation of rigid pipe with a diameter up to 6 inch.
The results of our Deepwater division are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data 19 Business Segment Information.
Our Shelf Contracting segment consists of CDI, our consolidated, majority-owned subsidiary. In shallower waters we provide manned diving, pipelay and pipe burial services, and platform installation and salvage 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 31 vessels, including 21 surface and saturation diving support vessels, six pipelay/pipebury barges, one dedicated pipebury barge, one combination derrick/pipelay barge and two derrick barges. Pipelay and pipe burial operations typically require extensive use of our diving services; therefore, we consider these services to be complementary.
Shelf Contracting performs saturation, surface and mixed gas diving which 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 nine saturation diving vessels and ten 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, 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.
On December 11, 2007, CDI completed its previously announced acquisition of Horizon, through the merger of Horizon with and into a wholly owned subsidiary of CDI, which resulted in Horizon becoming a wholly owned subsidiary of CDI. Under the terms of the merger, each share of common stock, par value $0.00001 per share, of Horizon was converted into the right to receive $9.25 in cash and 0.625 shares of CDIs common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at the effective time of the merger and converted into the right to receive the merger consideration. CDI issued an aggregate of approximately 20.3 million shares of common stock and paid approximately $300 million in cash in the merger. The cash portion of the merger consideration was paid from CDIs cash on hand and from
borrowings under its new $675 million credit facility consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility. See Item 8. Financial Statements and Supplementary Data Note 11 Long-Term Debt.
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 Horizon (2007), Acergy US, Inc. (Acergy) (2006), and the assets of Torch (2005). We also acquired Fraser Diving International Limited (Fraser) (2006).
Shelf Contracting 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 from the initial public offering (IPO), which included the sale of a 26.5% interest and transfer of debt to CDI. After the consummation of the Horizon acquisition, we currently own 58.5% of CDI.
We believe we are the global leader in rig alternative subsea well intervention. We engineer, manage and conduct well construction, intervention, and decommissioning operations in water depths ranging from 200 to 10,000 feet. 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 Operations services in both the Gulf of Mexico and the North Sea.
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 operations services at costs significantly less than drilling rigs. In the Gulf of Mexico, our multi-service semi-submersible vessel, the Q4000, has set a series of well operations firsts in increasingly deeper water without the use of a traditional drilling rig. In the North Sea, the Seawell has provided intervention and abandonment services for over 500 North Sea subsea wells since 1987. Competitive advantages of our vessels are derived from their lower operating costs, together with an ability to mobilize quickly and to maximize production time by performing a broad range of tasks 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 are constructing a newbuild North Sea vessel, the Well Enhancer. The expected cost of the new vessel is $198 million. We also expanded our operations geographically in Australia and Asia with the 2006 acquisition of Seatrac, an established Australian well operations company now called Well Ops SEA Pty. Limited.
The results of Well Operations are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data Note 19 Business Segment Information.
We own interests in certain production facilities in hub locations where there is potential for significant subsea tieback activity. There are a significant number of small discoveries that cannot justify the economics of a dedicated host facility. These discoveries are typically developed as subsea tie backs to existing facilities when capacity through the facility is available. We 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. Ownership of production facilities enables us to earn a transmission company type return through tariff charges while providing construction work for our vessels. We own a 50% interest in Deepwater Gateway, L.L.C., which owns the Marco Polo TLP, which was installed in 4,300 feet of water in the Gulf of Mexico in order to process production from Anadarko Petroleum Corporations Marco Polo field discovery. We also own a 20% interest in Independence Hub, LLC, an affiliate of Enterprise Products Partners L.P., which owns the Independence Hub platform, a 105-foot deep draft, semi-submersible platform located in a water depth of 8,000 feet that serves as a regional hub for up to 1 billion cubic feet of natural gas production per day from multiple ultra-deepwater fields in the previously untapped eastern Gulf of Mexico.
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, through a consolidated 50%-owned entity, we are currently converting a vessel into a dynamically positioned floating production unit. This unit 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 re-deployable facility is expected to be moved to a new location, contracted to a third party, or used to produce other internally-owned reservoirs.
In 2005, we acquired Helix Energy Limited, the largest outsource provider of sub-surface technology skills in the North Sea. With a technical staff of over 90 employees, we have the resources to provide valuable well enhancement services, which typically increase production or extend the life of a reservoir, to our own oil and natural gas projects as well as provide these services to our clients. Each team we assign to a specific client comprises a diverse set of skills, including reservoir engineering, geology, modeling, flow assurance, completions, well design and production enhancement. With offices in Aberdeen, London, Kuala Lumpur and Perth, we have an established market presence in regions that we have identified as strategically important to future growth. The results of reservoir and well technology services are reported under our Contracting Services segment. See Item 8. Financial Statements and Supplementary Data Note 19 Business Segment Information.
Contract drilling is a service we have not historically provided but have been contemplating since the construction of our Q4000 vessel over six years ago. Dayrates for deepwater drilling rigs have increased dramatically in recent years based on the significant oil and natural gas reserves located in deepwater regions and limited availability of rigs capable of drilling such depths. As a result, the drilling cost of a subsea development can be as much as 50% of the total F&D costs. We are currently adding drilling capability to the Q4000, a project scheduled for completion in the second quarter of 2008. The type of drilling intended for this vessel 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 will allow us to drill most of our own deepwater prospects and support the exploration and appraisal efforts of our clients. We expect approval from the MMS for cased well services including completions in 2008 and approval for drilling once we have satisfied MMS requirements.
We formed our oil and gas operations in 1992 to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services business and to achieve incremental additional returns to our contracting services. 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. In July 2006, we acquired Remington, an exploration, development and production company with operations primarily in the Gulf of Mexico, for approximately $1.4 billion in cash and Helix stock and the assumption of $358.4 million of liabilities. This acquisition 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, 2007, we had 677 Bcfe of proved reserves with 95% located in the Gulf of Mexico.
We believe that owning controlling interests in reservoirs, particularly in deepwater, accomplishes the following:
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, we have been 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.
Our oil and gas operations have a significant prospect inventory, mostly in the deepwater, which we believe will generate significant life of field services for our vessels. To minimize F&D costs, we intend to utilize the Q4000 for most of our deepwater drilling needs after the drilling upgrade is completed and regulatory approval has been obtained. Our Oil and Gas segment has a proven track record of cost effectively turning prospects into production on the OCS, and we believe similar success will continue to occur in the deepwater. Of the prospects we currently have in the deepwater, we intend to utilize the Q4000 for most of our drilling needs once the drilling upgrade is completed and regulatory approval has been granted. 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, our strategy is to drill one or more exploratory wells with partners. If the exploratory well(s) find commercial oil and/or gas reserves, we complete the well(s) and install the necessary infrastructure to begin producing the oil and/or gas. Because most of our operations are located 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 our 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. We seek to maximize profitability by lowering F&D costs, lowering development time and cost, operating the field more effectively, and 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 that 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 our financial strength, has made us the purchaser of choice of many major and independent oil and gas companies. In addition, our reservoir engineering and geophysical expertise, along with our access to contracting service assets that can positively impact development costs, have made us a preferred partner for many other oil and gas companies in offshore development projects. We share ownership in our oil and gas properties with various industry participants. We currently operate the majority of our offshore properties. An operator is generally able to maintain a greater degree of control over the timing and amount of capital expenditures than a non-operating interest owner. See Item 2. Properties Summary of Natural Gas and Oil Reserve Data for detailed disclosures of our oil and gas properties.
Revenue by geographic region during the years ended December 31, 2007, 2006 and 2005 were as follows (in thousands):
Property and equipment, net of depreciation, by geographic region during the years ended December 31, 2007, 2006 and 2005 were as follows (in thousands):
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 customers 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: 2007 Louis Dreyfus Energy Services (13%) and Shell Offshore, Inc. (10%); 2006 Louis Dreyfus Energy Services (10%) and Shell Offshore, Inc. (10%); and 2005 Louis Dreyfus Energy Services (10%) and Shell Trading (US) Company (10%). All of these customers were purchasers of our oil and gas production. We estimate that in 2007 we provided subsea services to over 200 customers.
Our contracting services projects have historically been of short duration and are generally awarded shortly before mobilization. As a result, no significant backlog existed prior to 2007. In 2007, we entered into several long-term contracts, for certain of our Deepwater and Well Operations 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.
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, Allseas, 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. 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. Many of our competitors may have significantly more financial, personnel, technological, and other resources
available. In addition, some of the larger integrated companies may be better able to respond to industry changes including price fluctuation, oil and gas demands, and governmental regulations. Small or mid-sized producers, and in some cases financial players, with a focus on acquisition of proved developed and undeveloped reserves are often competition on development properties.
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 and 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 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 effort, progressive auditing is done to continuously improve our EHS management system.
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 (USCG), 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 (ABS). 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 tax laws and policies relating to the oil and gas industry generally. In particular, the development and operation of oil and gas properties located on the OCS of the United States is regulated primarily by the 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 (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 (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.
Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials (including oil) into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed. Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.
The Oil Pollution Act of 1990, as amended (OPA), imposes a variety of requirements on Responsible Parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the
United States. A Responsible Party includes the owner or operator of an onshore facility, a vessel or a pipeline, and the lessee or permittee of the area in which an offshore facility is located. OPA imposes liability on each Responsible Party for oil spill removal costs and for other public and private damages from oil spills. Failure to comply with OPA may result in the assessment of civil and criminal penalties. OPA establishes liability limits of $350 million for onshore facilities, all removal costs plus $75 million for offshore facilities, and the greater of $800,000 or $950 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 19 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.
We rely on the high quality of our workforce. As of January 31, 2008, we had over 3,370 employees, nearly 1,000 of which were salaried personnel. Of the total employees, approximately 2,000 were employees of Cal Dive. As of December 31, 2007, we also contracted with third parties to utilize approximately 300 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 favorable.
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, 2007, and copies of our Quarterly Reports on Form 10-Q for 2007 and 2008 and any Current Reports on Form 8-K for 2007 and 2008, and any amendments thereto, are or will be available free of charge at such website as soon as reasonably practicable after they are filed with, or furnished to, the Securities and Exchange Commission (SEC). 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 SECs 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 SECs 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.
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 has continued to improve during 2007, following higher commodity prices from 2003 to 2007. We cannot assure you that activity levels for offshore construction 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.
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 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 our partial divestiture of Cal Dive, 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 us.
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 of Mexico and North Sea are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the summer and fall when weather conditions are favorable for offshore exploration, development and construction activities. We typically have experienced our lowest utilization rates in the first quarter. As is common in the industry, we typically bear the risk of delays caused by some adverse weather conditions. Accordingly, our results in any one quarter are not necessarily indicative of annual results or continuing trends.
Certain areas in and near the Gulf of Mexico and North Sea experience unfavorable weather conditions including hurricanes and other extreme weather conditions on a relatively frequent basis. Substantially all of our facilities and assets offshore and along the Gulf of Mexico and the North Sea, including our vessels and structures on our offshore oil and gas properties, are susceptible to damage and/or total loss by these storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail both service and production operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because customers may curtail their development activities due to damage to their platforms, pipelines and other related facilities.
A significant amount of our projects are performed on a qualified turnkey basis where described work is delivered for a fixed price and extra work, which is subject to customer approval, is billed separately. The revenue, cost and gross profit realized on a turnkey contract can vary from the estimated amount because of changes in offshore job conditions, variations in labor and equipment productivity from the original estimates, the performance of third parties such as equipment suppliers, or other factors. These variations and risks inherent in the marine construction industry may result in our experiencing reduced profitability or losses on projects.
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 assets 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/or result in a total loss of our investment, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells.
Projecting future natural gas and oil production is imprecise. Producing oil and gas reservoirs eventually have declining production rates. Projections of production rates rely on certain assumptions regarding historical production patterns in the area or formation tests for a particular producing horizon. Actual production rates could differ materially from such projections. Production rates also can depend on a number of additional factors, including commodity prices, market demand and the political, economic and regulatory climate.
Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:
If any of these events occurs, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.
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 crude oil and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions, or other factors affecting those assumptions, could impair the quantity and value of our crude oil and natural gas reserves.
This Annual Report contains estimates of our proved oil and gas reserves and the estimated future net cash flows therefrom based upon reports for the years ended December 31, 2007 and 2006, audited by our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC, as to oil and gas prices, drilling and operating expenses, capital expenditures, 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 and production expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary from those estimated in these reports. Any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. You should not assume that the present value of future net cash flows from our proved reserves referred to in this Annual Report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on 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.
Approximately 79% of our total estimated proved reserves are either PDNP or PUD and those reserves may not ultimately be produced or developed.
As of December 31, 2007, approximately 12% of our total estimated proved reserves were PDNP and approximately 67% were PUD. These reserves may not ultimately be developed or produced. Furthermore, not all of our PUD or PDNP may be ultimately produced during the time periods we have planned, at the costs we have budgeted, or at all, which in turn may have a material adverse effect on our results of operations.
Oil and gas properties are depleting assets. We replace reserves through acquisitions, exploration and exploitation of current properties. Approximately 79% of our proved reserves at December 31, 2007 are PUDs and PDNP. Further, our proved producing reserves at December 31, 2007 are expected to experience annual decline rates ranging from 30% to 40% over the next ten years. If we are unable to acquire additional properties or if we are unable to find additional reserves through exploration or exploitation of our properties, our future cash flows from oil and gas operations could decrease.
We are in part dependent on third parties with respect to the transportation of our oil and gas production and in certain cases, third party operators who influence our productivity.
Notwithstanding our ability to produce hydrocarbons, we are dependent on third party transporters to bring our oil and gas production to the market. In the event a third party transporter experiences operational difficulties, due to force majeure, 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.
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
Our substantial indebtedness could impair our financial condition and our ability to fulfill our debt obligations.
As of December 31, 2007, we had approximately $1.8 billion of consolidated 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.
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.
In addition, the delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. Our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our industry is high, and the supply is limited. In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
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.
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 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 agencies issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials including oil into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed.
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 environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future. Such environmental liability could
substantially reduce our net income and could have a significant impact on our financial ability to carry out our operations.
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 discourage a takeover proposal or tender offer not approved by management and the board of directors and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less for their shares than otherwise might be available in the event of a takeover attempt.
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.
We own a fleet of 41 vessels and 33 ROVs, 4 trenchers, and 2 ROVDrills. We also lease four vessels, one trencher and one ROV. 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.
Acquisitions in 2007
On December 11, 2007, our majority-owned subsidiary, CDI, completed its previously announced acquisition of Horizon through the merger of Horizon with and into a wholly owned subsidiary of CDI, which resulted in Horizon becoming a wholly owned subsidiary of CDI. Under the terms of the merger, each share of common stock, par value $0.00001 per share, of Horizon was converted into the right to receive $9.25 in cash and 0.625 shares of CDIs common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at the effective time of the merger and converted into the right to receive the merger consideration. CDI issued an aggregate of approximately 20.3 million shares of common stock and paid approximately $300 million in cash in the merger. The cash portion of the merger consideration was paid from CDIs cash on hand and from borrowings under CDIs new $675 million credit facility consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility. See Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources.
In July 2007, we acquired the remaining 42% interest in Well Ops SEA Pty Ltd (formerly Seatrac) for total consideration of approximately $10.1 million (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 October 2006 when we purchased the initial 58% interest.
Divestitures in 2007
On September 30, 2007, we sold a 30% working interest in the Phoenix oilfield (Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon Block 282) and the Little Burn oilfield (Green Canyon Block 238) to Sojitz GOM Deepwater, Inc. (Sojitz), a wholly owned subsidiary of Sojitz Corporation, for a cash payment of $40 million and the proportionate recovery of all past and future capital expenditures related to the re-development of the fields, excluding the conversion of the Helix Producer I, which we plan to use as a redeployable floating production unit (FPU). Proceeds of $51.2 million from the sale were collected in October 2007. Sojitz will also pay its proportionate share of the operating costs including fees payable for the use of the FPU. A gain of approximately $40.4 million was recorded in 2007 as a result of this sale.
In December 2006, we acquired a 100% working interest in the Camelot gas field in the North Sea in exchange for the assumption of certain decommissioning liabilities estimated at approximately $7.6 million. In June 2007, we sold a 50% working interest in this property for approximately $1.8 million cash and the assumption by the purchaser of 50% of the decommissioning liability of approximately $4.0 million. We recognized a gain of approximately $1.6 million as a result of this sale.
Listing of Vessels, Barges and ROVs Related to Contracting Services Operations(1)
In addition to CDIs saturation diving vessels, CDI currently owns ten portable saturation diving systems, including six acquired from Fraser.
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, 2007, 2006 and 2005:
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.
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 Corporations 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 owns the Independence Hub platform, a 105 foot deep draft, semi-submersible platform located in Mississippi Canyon block 920 in a water depth of 8,000 feet that serves as a regional hub for natural gas production from multiple ultra-Deepwater fields in the previously untapped eastern Gulf of Mexico. First production began in July 2007. The Independence Hub facility is 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 (Kerr-McGee), 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 LLC to convert a ferry vessel into a dynamically-positioned minimal floating production system to be named Helix Producer I. 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 in the second quarter of 2008 for approximately $87 million. The second phase of the conversion is expected to be completed in the third quarter of 2008. Estimated cost of conversion for the second phase is approximately $117 million, of which we expect to fund 100%.
We employ full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in conformance with SEC guidelines. Engineering reserve estimates were prepared by us based upon our interpretation of production performance data and sub-surface information derived from the drilling of existing wells. Our internal reservoir engineers and independent petroleum engineers analyzed 100% of our United States oil and gas fields on an annual basis (143 fields as of December 31, 2007). We consider any field with discounted future net revenues of 1% or greater of the total discounted future net revenues of all our fields to be significant. An engineering audit, as we use the term, is a process involving an independent petroleum engineering firms (Huddleston & Co., Inc. (Huddleston)) extensive visits, collection and examination of all geologic, geophysical, engineering and economic data requested by the independent petroleum engineering firm. Our use of the term engineering audit is intended only to refer to the collective application of the procedures which Huddleston was engaged to perform and may be defined and used differently by other companies.
The engineering audit of our reserves by the independent petroleum engineers involves their rigorous examination of our technical evaluation, interpretation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Our internal reservoir engineers interpret this data to determine the nature of the reservoir and ultimately the quantity of proved oil and gas reserves attributable to a specific property. Our proved reserves in this Annual Report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Huddleston also examined our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
In the conduct of the engineering audit, Huddleston did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties or sales of production. However, if in the course of the examination something came to the attention of Huddleston which brought into question the validity or sufficiency of any such information or data, Huddleston did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, Huddleston evaluated our volumetric analysis, which included the analysis of production and pressure data. Each of the PUDs analyzed by Huddleston included volumetric analysis, which took into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, Huddleston examined data related to well spacing, including potential drainage from offsetting producing wells in evaluating proved reserves for un-drilled well locations.
The engineering audit by Huddleston included 100% of our producing properties together with a percentage of our non-producing and undeveloped properties. Properties for analysis were selected by us and Huddleston based on discounted future net revenues. All of our significant properties were included in the engineering audit and such audited properties constituted 97% of the total discounted future net revenues. Huddleston audited approximately 96% of our total reserve base in the United States, including what was deemed to be the most valuable properties. Huddleston audited 92% of proved developed reserves and 98% of the proved undeveloped reserves totaling 96% of both categories combined. Huddleston also analyzed the methods utilized by us in the preparation of all of the estimated reserves and revenues. Huddleston represents in its audit report that they believe our methodologies are consistent with the methodologies required by the SEC, Society of Petroleum Engineers (SPE) and FASB. There were no limitations imposed, nor limitations encountered by us or Huddleston.
The table below sets forth information, as of December 31, 2007, with respect to estimates of net proved reserves. 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 21 Supplemental Oil and Gas Disclosures.
Significant Oil and Gas Properties
Our oil and gas properties consist primarily of interests in developed and undeveloped oil and gas leases. As of December 31, 2007, we had exploration, development and production operations in the United States, primarily in the Gulf of Mexico. In December 2006, we acquired the Camelot field, located in the North Sea, in which we subsequently sold a 50% interest in June 2007. This is our only oil and gas property in the United Kingdom.
Our U.S. operations accounted for 99% of our 2007 production and approximately 98% of total proved reserves at December 31, 2007 (79% of such total reserves are PUDs and PDNP). Further, our proved producing reserves at December 31, 2007 are expected to experience annual decline rates ranging from 30% to 40% over the next ten years. The following table provides a brief description of our domestic and international oil and gas properties we consider most significant to us at December 31, 2007:
United States Offshore
We have proved reserves of approximately 304 Bcfe in five fields in the Gulf of Mexico Deepwater which comprised approximately 45% of our total proved reserves as of December 31, 2007. The working interests in these fields range from 17.5% to 100%. We are the operator of two of the five fields, which comprised approximately 82% of our Deepwater proved reserves (approximately 37% of total proved reserves). Gunnison, a non-operated field, has been producing since December 2003. Our net production in Deepwater totaled approximately 13 Bcfe in 2007. We continue to be active in Deepwater with an ongoing exploration and development program.
We have proved reserves of approximately 336 Bcfe in over 130 fields in the Gulf of Mexico on the OCS which comprised approximately 50% of total proved reserves as of December 31, 2007. Our net production on the OCS totaled approximately 50 Bcfe in 2007. The working interests in our OCS fields range from 3% to 100%. Our largest field based on proved reserves is East Cameron 346, with approximately 11% of OCS reserves (approximately 6% of total proved reserves). No other individual OCS field comprised over 5% of total proved reserves. We are the operator of 75% of our OCS proved reserves. We continue to be active on the OCS with an ongoing exploration and development program. Based on current market conditions, we plan to drill approximately 11 wells on the OCS in 2008.
We have proved reserves of approximately 22 Bcfe in over 17 onshore fields in Mississippi, Alabama, Louisiana and Texas, with net production totaling approximately two Bcfe in 2007. Our U.S. onshore proved reserves comprised approximately 3% of total proved reserves as of December 31, 2007. The working interests in our onshore properties range from 7% to 93.6%. We are not the operator of most of the onshore fields. One onshore non-operated field (Parker Creek) in Mississippi comprised over 71% of our U.S. onshore reserves, but only
approximately 2% of our total proved reserves. There are no significant developments scheduled for the onshore fields.
In December 2006, we acquired the Camelot field, located in the North Sea, in which we subsequently sold a 50% interest in June 2007. This is our only oil and gas property in the United Kingdom.
Production, price and cost data for our oil and gas operations in the United States are as follows:
No production data is available for our oil and gas operations in the United Kingdom in 2005 and 2006 as we acquired Camelot in December 2006 (which was not then producing). Production in 2007 was insignificant (0.3 Bcfe of gas).
The number of productive oil and gas wells in which we held interest as of December 31, 2007 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 multiple completions and non-producing wells as of December 31, 2007:
Developed and Undeveloped Acreage
The developed and undeveloped acreage (including both leases and concessions) that we held at December 31, 2007 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):
The following table shows the results of oil and gas wells drilled in the United States for each of the years ended December 31, 2007, 2006 and 2005:
No wells were drilled in the United Kingdom in 2007, 2006 and 2005.
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, 2007, our oil and gas operations were completing one development well and one exploration well. See Item 8. Financial Statements and Supplementary Data Note 7 Oil and Gas Properties. These wells are located in the Gulf of Mexico.
Our corporate headquarters are located at 400 N. Sam Houston Parkway E., Suite 400, Houston, Texas. The corporate headquarters of CDI are located at 2500 CityWest Boulevard, Suite 2200, Houston Texas. Our primary subsea and marine services operations are based in Port of Iberia, Louisiana. We own the Aberdeen (Dyce), Scotland facility and CDI owns approximately 61/2 acres of the Port of Iberia, Louisiana facility and its Port Arthur and Sabine, Texas facilities. All other facilities are leased.
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 employers liability, general liability and other insurance customary in our business. All insurance is carried at levels of coverage and deductibles that 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 also are involved in various legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United State 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.
On December 2, 2005, we received an order from the 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 Outer Continental Shelf 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, 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, including ours. On October 30, 2007, the federal district court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held that the Department of the Interior exceeded its authority by including the price thresholds in the subject leases. The government filed a notice of appeal of that decision on December 21, 2007. 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 in a final decision. 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, 2006 and 2007) plus interest at 5% for our portion of the Gunnison related MMS claim. The total reserved amount at December 31, 2007 was approximately $55.1 million and was included in Other Long Term Liabilities in the accompanying consolidated balance sheet included herein. 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.
During the fourth quarter of 2006, Horizon received a tax assessment from the Servicio de Administracion Tributaria (SAT), the Mexican taxing authority, for approximately $23 million related to fiscal 2001, including penalties, interest and monetary correction. The SATs assessment claims unpaid taxes related to services performed among the Horizon subsidiaries that CDI acquired at the time it acquired Horizon. CDI believes under the Mexico and United States double taxation treaty that these services are not taxable and that the tax assessment itself is invalid. On February 14, 2008, CDI received notice from the SAT upholding the original assessment. We believe that CDIs position is supported by law and CDI intends to vigorously defend its position. However, the ultimate outcome of this litigation and CDIs potential liability from this assessment, if any, cannot be determined at this time. Nonetheless, an unfavorable outcome with respect to the Mexico tax assessment could have a material adverse effect on our financial position and results of operations. Horizons 2002 through 2007 tax years remain subject to examination by the appropriate governmental agencies for Mexico tax purposes, with 2002 and 2003 currently under audit.
The executive officers of Helix are as follows:
Owen Kratz is President and Chief Executive Officer 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 subsequently resumed his role as Chief Executive Officer on February 4, 2008 upon the resignation of Mr. Martin R. Ferron, and was subsequently elected President and Chief Executive Officer on February 28, 2008. 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.
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 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 17 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 Halliburtons 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.
Martin Ferron resigned as our President and Chief Executive Officer effective February 4, 2008. Concurrently, Mr. Ferron resigned from our Board of Directors. Mr. Ferron remained employed by us through February 18, 2008, after which his employment was terminated. At the time of Mr. Ferrons resignation, Owen Kratz, who served as Executive Chairman, resumed the role and assumed the duties of the President and Chief Executive Officer, and was subsequently elected as President and Chief Executive Officer of Helix,.
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 26, 2008, the closing sale price of our common stock on the NYSE was $34.63 per share. As of February 22, 2008, there were an estimated 312 registered shareholders 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 Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources.
The following graph compares the cumulative total shareholder return on our common stock for the period since December 31, 2002 to the cumulative total shareholder return for (i)the stocks of 500 large-cap corporations maintained by Standard & Poors (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., Oceaneering International, Inc., Cameron International Corporation, Pride International, Inc., Oil States International, Inc., Grant Prideco, Inc., Rowan Companies, Inc., Complete Production Services, Inc., Tidewater Inc., 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 companys equity market capitalization as of December 31, 2007 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, 2002 in our common stock at the closing price on that date price and on December 31, 2002 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 253.2%; the Peer Group 273.3%; the OSX 258.9%; and S&P 500- 74.9%. These results are not necessarily indicative of future performance.
Issuer Purchases of Equity Securities
The financial data presented below for each of the five years ended December 31, 2007, should be read in conjunction with Item 7. Managements 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 managements 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.
We are an international offshore energy company that provides reservoir development solutions and other contracting 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 costs, relative to industry norms.
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:
Over the last few years we continued to evolve the Helix model by completing a variety of transactions and events that 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 Offshore, Inc. and Acergy US Inc. 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 Technology Services group through the acquisition of Helix Energy Limited for $32.7 million and the assumption of $7.5 million of liabilities. In 2006, we acquired Remington, an exploration, development and production company, for approximately $1.4 billion in cash and stock and the assumption of $358.4 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 Shelf Contracting subsidiary, and in December 2006 completed a carve-out initial public offering of that company, selling a 26.5% stake and receiving pre-tax net proceeds of $264.4 million from Cal Dive and a pre-tax dividend of $200 million from additional borrowings under the Cal Dive revolving credit facility.
During 2006 we committed to four capital projects which will significantly expand our contracting services capabilities: conversion of the Caesar into a deepwater pipelay vessel, upgrading of the Q4000 to include drilling capability, conversion of a ferry vessel into a DP floating production unit (Helix Producer I) and construction of a multi-service DP dive support/well intervention vessel for the North Sea (Well Enhancer). During 2007, we successfully completed the drilling of exploratory wells in our 100% owned Noonan and Danny prospects located in Garden Banks Block 506 in the Gulf of Mexico. First production for Noonan is expected in the second half of 2008 and Danny is expected in the first half of 2009.
In June 2007, Cal Dive and Horizon announced that they had entered into an agreement under which Cal Dive would acquire Horizon for approximately $650.0 million. CDI issued an aggregate of approximately 20.3 million shares of common stock and paid approximately $300 million in cash in the merger. The cash portion of the merger consideration was paid from CDIs cash on hand and from borrowings under its new $675 million credit facility consisting of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility, each of which is non-recourse to Helix. As a result of CDIs equity issued, we recorded a $98.6 million gain, net of $53.1 million of taxes. The gain was calculated as the difference in the value of our investment in CDI immediately before and after CDIs stock issuance. The transaction closed on December 11, 2007.
Our operations are conducted through the following lines of business: contracting services operations and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Production Facilities, and Oil and Gas. Contracting Services operations include services such as deepwater pipelay, well operations, robotics and reservoir and well technology services. Shelf Contracting operations represent Cal Dive, in which we owned 58.5% at December 31, 2007. All material intercompany transactions between the segments have been eliminated in our consolidated results of operations.
Comparison of Years Ended December 31, 2007 and 2006
The following table details various financial and operational highlights for the periods presented:
Intercompany segment revenues during the years ended December 31, 2007 and 2006 were as follows (in thousands):
Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2007 and 2006 were as follows (in thousands):
The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented (U.S. operations only as U.K. operations were immaterial for the periods presented):
Presenting the expenses of our Oil and Gas segment (U.S. operations only) on a cost per Mcfe of production basis normalizes for the impact of production gains/losses and provides a measure of expense control efficiencies. The following table highlights certain relevant expense items in total (in thousands) and on a cost per Mcfe of production basis (with barrels of oil converted to Mcfe at a ratio of one barrel to six Mcf):
Revenues. During the year ended December 31, 2007, our revenues increased by 29% as compared to 2006. Contracting Services revenues increased primarily due to improved contract pricing for the pipelay, well operations and ROV divisions. Shelf Contracting revenues increased primarily as a result of the initial deployment of certain assets we acquired through the Torch, Acergy and Fraser acquisitions that came into service subsequent to the first quarter of 2006 as well as the Horizon assets acquired in late 2007. These increases were partially offset by two vessels CDI did not operate (one owned and one chartered) in 2007 that were in operation in 2006 and an increased number of out-of-service days for regulatory drydock and vessel upgrades for certain vessels in our Shelf Contracting segment.
Oil and Gas revenues increased 36% during 2007 as compared to the prior year. The increase was primarily due to increases in oil and natural gas production. The production volume increase of 33% over 2006 was mainly attributable to properties acquired in connection with the Remington acquisition, which closed on July 1, 2006.
Gross Profit. The Contracting Services gross profit increase was primarily attributable to improved contract pricing for the pipelay, well operations and ROV divisions. The gross profit increase within Shelf Contracting was primarily attributable to increased gross profit derived from the initial deployment of certain assets we acquired subsequent to the first quarter 2006, offset by increased out-of-service days referred to above, lower vessel utilization as a result of seasonal weather in the fourth quarter 2007, and increased depreciation and deferred drydock amortization.
The Oil and Gas gross profit decrease in 2007 as compared to 2006 was primarily due to the following factors:
including approximately $12.5 million of increased fourth quarter 2007 depletion due to certain producing properties experiencing significant proved reserve declines;
As a result of our unsuccessful development well in January 2008 on Devils Island, we expect to expense an additional $13 million in the first quarter of 2008. Costs incurred as of December 31, 2007 related to this well were charged to income in 2007 and were included in the 2007 impairment expense described above.
Gain on Sale of Assets, Net. Gain on sale of assets, net, increased by $47.6 million during 2007 as compared to 2006. On September 30, 2007, we sold a 30% working interest in the Phoenix oilfield (Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon Block 282) and the Little Burn oilfield (Green Canyon Block 238) to Sojitz for a cash payment of $51.2 million and recognized a gain of $40.4 million in 2007. We also recognized the following gains in 2007:
Selling and Administrative Expenses. Selling and administrative expenses of $151.4 million were $31.8 million higher than the $119.6 million incurred in 2006. The increase was due primarily to higher overhead to support our growth and increased incentive compensation accruals. Further, in June 2007, CDI recorded a $2.0 million charge for a cash settlement with the Department of Justice. Selling and administrative expenses as a percent of revenues were 9% for both 2007 and 2006.
Equity in Earnings of Investments, Net of Impairment Charge. Equity in earnings of investments increased by $1.6 million during 2007 as compared to 2006. Equity in earnings related to our 20% investment in Independence Hub increased $10.5 million as we reached mechanical completion in March 2007 and began receiving demand fees and tariffs as production began in the third quarter. In addition, equity in earnings of our 50% investment in Deepwater Gateway increased by $2.2 million in 2007 as compared to 2006 due to higher throughput at the Marco Polo TLP. These increases were offset by second quarter 2007 equity losses from CDIs 40% investment in OTSL and a related non-cash asset impairment charge together totaling $11.8 million.
Net Interest Expense and Other. We reported net interest and other expense of $59.4 million in 2007 as compared to $34.6 million in the prior year. Gross interest expense of $100.4 million during 2007 was higher than the $51.9 million incurred in 2006 as a result of our Term Loan and Revolving Loans, which closed in July 2006, and CDIs revolving credit facility, which closed in December 2006. Offsetting the increase in interest expense was $31.8 million of capitalized interest and $9.5 million of interest income in 2007, compared with $10.6 million of capitalized interest and $6.3 million of interest income in the same prior year period. We expect interest expense to increase in 2008 as a result of the Senior Unsecured Notes we issued in December 2007 and the Term Loan CDI entered into as a result of the Horizon acquisition. See Item 8. Financial Statements and Supplementary Data Note 11 Long-Term Debt for detailed description of these notes.
Gain on Subsidiary Equity Transaction. We recognized a non cash pre-tax gain of $151.7 million ($98.6 million net of taxes of $53.1 million) in 2007 as our share of CDIs underlying equity increased as a result of CDIs issuance of 20.3 million shares of its common stock to former Horizon stockholders in connection with CDIs acquisition of Horizon, which reduced our ownership in CDI to 58.5%. The non-cash gain is derived from the difference in the value of our investment in CDI immediately before and after the acquisition. In 2006, CDI received net proceeds of $264.4 million from the initial public offering of 22.2 million shares of its common stock. Together with CDIs drawdown of its revolving credit facility, CDI paid pre-tax dividends of $464.4 million to us in December 2006. As a result of these transactions, we recorded a pre-tax gain of $223.1 million ($96.5 million net of taxes of $126.6 million) in 2006.
Provision for Income Taxes. Income taxes decreased to $174.9 million in 2007 compared to $257.2 million in the prior year. $126.6 million of the income tax expense decrease was related to the CDI dividends paid to us in 2006. This decrease was partially offset by increased profitability in 2007. The effective tax rate of 33.3% for 2007 was lower than the 42.5% effective tax rate for same period 2006 due primarily to the CDI dividends of $464.4 million received in December 2006. We expect our 2008 income tax rate to be higher than it has historically been as a result of providing a deferred tax liability on the difference between the book and tax basis of our investment in CDI.
Comparison of Years Ended December 31, 2006 and 2005
The following table details various financial and operational highlights for the periods presented:
Intercompany segment revenues during the years ended December 31, 2006 and 2005 were as follows (in thousands):
Intercompany segment profit (which only relates to intercompany capital projects) during the years ended December 31, 2006 and 2005 were as follows (in thousands):
The following table details various financial and operational highlights related to our oil and gas operations for the periods presented (U.S. operations only as U.K. operations were immaterial for the periods presented):
Presenting the expenses of our Oil and Gas segment (U.S. operations only) on a cost per Mcfe of production basis normalizes for the impact of production gains/losses and provides a measure of expense control efficiencies. The following table highlights certain relevant expense items in total (in thousands) and on a cost per Mcfe of production basis (with barrels of oil converted to Mcfe at a ratio of one barrel to six Mcf):
Revenues. During the year ended December 31, 2006, our revenues increased by 71% as compared to 2005. Contracting Services revenues increased primarily due to improved market demand (resulting in improved contract pricing for the Pipelay, Well Operations and ROV divisions), and the addition of the Express acquired from Torch in 2005 and Helix Energy Limited acquired in 2005. Shelf Contracting revenue increased due to the additional vessels acquired from Acergy and Torch during 2005 and improved market demand, much of which was the result of damages sustained in the 2005 hurricanes in the Gulf of Mexico. This resulted in significantly improved utilization rates and an overall increase in pricing for our Shelf Contracting services.
Oil and Gas revenue increased 56%, during 2006 compared with the prior year. The increase was primarily due to increases in oil and natural gas production. The production volume increase of 47% over 2005 was mainly attributable to the full second half impact of the Remington acquisition, partially offset by continued pipeline shut-ins on certain fields. Oil and Gas revenue also increased due to higher oil prices realized in 2006 as compared to 2005, offset slightly by a $0.22 decline in average realized gas prices.
Gross Profit. Gross profit in 2006 increased 82% as compared to the same period in 2005. The Contracting Services gross profit increase was primarily attributable to improved contract pricing for the Pipelay, Well Operations and ROV divisions, and the addition of the Express. The gross profit increase within Shelf Contracting was primarily attributable to additional gross profit derived from the Torch and Acergy acquisitions, improved utilization rates and increased contract pricing as discussed above.
Oil and Gas gross profit increased 14% in 2006 compared to 2005. Gross profit was negatively impacted by $43.1 million of exploration costs incurred during 2006 compared with $6.5 million incurred in 2005. The increase in exploration costs was primarily due to dry hole costs of $21.7 million related to the Tulane prospect as a result of mechanical difficulties experienced in the drilling of this well. The well was subsequently plugged and abandoned in the first quarter of 2006. In addition, we incurred dry hole costs totaling approximately $15.9 million in the third quarter of 2006 associated with two deep shelf wells commenced by Remington prior to the acquisition. We expensed inspection and repair costs of approximately $16.8 million as a result of Hurricanes Katrina and Rita, partially offset by $9.7 million in insurance recoveries in 2006 compared to $7.1 million of hurricane inspection and repair costs in 2005. In addition, depletion and amortization per Mcfe increased 30% in 2006 compared to 2005 due primarily to the acquisition costs associated with the Remington properties acquired in July 2006. These decreases were offset by higher oil prices realized and higher oil and gas production as discussed above.
In addition, in 2005 we recorded $2.7 million of losses associated with hedge instrument ineffectiveness as a result of production shut-ins caused by the aforementioned hurricanes. No hedge ineffectiveness was recorded in 2006.
Selling and Administrative Expenses. Selling and administrative expenses of $119.6 million were $56.8 million higher than the $62.8 million incurred in 2005. The increase was due primarily to higher overhead to support our growth. Selling and administrative expenses increased slightly to 9% of revenues in 2006 compared to 8% in 2005.
Equity in Earnings of Investments. Equity in earnings of our 50% investment in Deepwater Gateway, L.L.C. increased to $18.4 million in 2006 compared with $10.6 million in 2005 due to increased throughput at the Marco Polo TLP. Further, equity losses in our 40% minority ownership interest in OTSL for 2006 totaled approximately $487,000 compared with equity earnings of $2.8 million in 2005.
Gain on Subsidiary Equity Transaction. Gain on subsidiary equity transaction of $223.1 million is related to the CDI initial public offering of 22,173,000 shares of its common stock in December 2006, together with shares issued to CDI employees immediately after the offering, our ownership reduced to 73.0%. CDI received net proceeds of $264.4 million from its initial public offering. Together with CDIs drawdown of its revolving credit facility, CDI paid pre-tax dividends of $464.4 million to us in December 2006. The gain is as a result of these transactions.
Net Interest Expense and Other. We reported interest and other expense of $34.6 million in 2006 compared to $7.6 million in the prior year. Gross interest expense of $51.9 million during 2006 was higher than the $15.0 million incurred in 2005. Approximately $31.4 million of the increase was related to our Term Loan which closed in July 2006 and $2.4 million of the increase was related to our $300 million Convertible Senior Notes which closed in
March 2005. Offsetting the increase in interest expense was $10.6 million of capitalized interest in 2006, compared with capitalized interest of $2.0 million in the prior year.
Provision for Income Taxes. Income taxes increased to $257.2 million in 2006 compared to $75.0 million in the prior year. $126.6 million of the income tax expense increase was related to the CDI dividends to us. The remaining increase was primarily due to increased profitability. The effective tax rate of 42.5% for 2006 was higher than the 33.0% effective tax rate for same period in 2005 due primarily to the CDI dividends of $464.4 million received in December 2006.
Liquidity and Capital Resources
The following tables present certain information useful in the analysis of our financial condition and liquidity for the periods presented (in thousands):
Our primary cash needs are to fund capital expenditures to allow the growth of our current lines of business and to repay outstanding borrowings and make related interest payments. Historically, we have funded our capital program, including acquisitions, with cash flows from operations, borrowings under credit facilities and use of project financing along with other debt and equity alternatives. Some of the significant financings, and corresponding uses, during 2007 were as follows:
Some of the significant financings and corresponding uses during 2006 and 2005 were as follows:
In accordance with our Senior Unsecured Notes, Senior Credit Facilities, the Convertible Senior Notes, the MARAD debt and Cal Dives credit facilities, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of December 31, 2007, we were in compliance with these covenants. The Senior Credit Facilities contain provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by the Company. The Senior Credit
Facilities do permit us to incur unsecured indebtedness, and also provide for our subsidiaries to incur project financing indebtedness (such as our MARAD loans) secured by the underlying asset, provided that the indebtedness is not guaranteed by us. Upon the occurrence of certain dispositions or the issuance or incurrence of certain types of indebtedness, we may be required to prepay a portion of the Term Loan equal to the amount of proceeds received from such occurrences. Such prepayments will be applied first to the Term Loan, and any excess will be applied to the Revolving Loans, if any.
As of December 31, 2007, we had approximately $241 million of available borrowing capacity under our credit facilities, and CDI had $273 million of available borrowing under its revolving credit facility. See Note 11 Long-term Debt in Item 8. Financial Statements and Supplementary Data for additional information related to our long-term debts, including our obligations under capital commitments.
Cash flow from operating activities decreased $97.7 million in 2007 as compared to 2006 primarily due to negative working capital changes in 2007. Compared to 2006, increased expenditures in other noncurrent assets, net, consisted of an additional $21.6 million in drydock expenses (net of amortization), $8.8 million for an equipment deposit and $14.6 million related to a non-current contract receivable for retainage. Working capital, net of cash, decreased approximately $145.5 million in 2007 when compared to 2006. Cash from operating activities was negatively impacted by higher income taxes paid in 2007 versus 2006 of approximately $146.9 million, of which $126.6 million was related to CDIs initial public offering. These decreases were partially offset by increase in profitability, excluding the impact of non-cash related items, in 2007 as compared to 2006.
Cash flow from operating activities increased $271.6 million in 2006 as compared to 2005. This increase was primarily due to higher net income and positive working capital changes. Of the $194.8 million increase in net income in 2006, compared with 2005, approximately $96.5 million, net of $126.6 million of taxes, was related to the gain on the CDI initial public offering and related debt push down to CDI. Further, the net income increased due to higher oil and gas production and oil price realized in 2006, and as a result of net income contribution from the Remington, Acergy and Torch acquisitions. Cash from operating activities was more favorable in 2006 as compared to 2005 due to higher income tax payable, which we expect to pay in the first quarter of 2007 and as a result of more favorable accounts receivable turnover.
Capital expenditures have consisted principally of strategic asset acquisitions related to the purchase or construction of DP vessels, acquisition of select businesses, improvements to existing vessels, acquisition of oil and gas properties and investments in our Production Facilities. Significant sources (uses) of cash associated with investing activities for the years ended December 31, 2007, 2006 and 2005 were as follows (in thousands):