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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K/A
Amendment No. 1
(Mark One)
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Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2006
or
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from to
Commission File Number 001-32936
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
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Minnesota
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953409686 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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400 N. Sam Houston Parkway E.
Suite 400
Houston, Texas
(Address of principal executive offices)
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77060
(Zip Code) |
(281) 6180400
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered |
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Common Stock (no par value)
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New York Stock Exchange |
Securities registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined
in Rule 405 of the Securities Act.
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, or a non-accelerated filer. See definition of accelerated filer and
large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). o Yes þ No
The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant as of June 30, 2006 was $2,926,119,938 based on the last
reported sales price of the Common Stock on June 30, 2006, as reported on the NASDAQ
National Market System. On July 18, 2006, the registrants Common Stock began trading on
the New York Stock Exchange.
The number of shares of the registrants Common Stock outstanding as of May 31, 2007 was
91,321,577.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders held on
May 7, 2007, are incorporated by reference into Part III hereof.
HELIX ENERGY SOLUTIONS GROUP, INC. INDEX FORM 10-K/A
EXPLANATORY NOTE
Helix Energy Solutions Group, Inc. (Helix) is filing this amendment to its Annual Report on
Form 10-K for the fiscal year ended December 31, 2006 that was originally filed on March 1, 2007
(the Original 10-K) in response to comments received from the Securities and Exchange
Commissions Division of Corporation Finance. This amendment includes the following:
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Item 1A. Risk Factors, revised to change the title of the risk factor Estimates of our
oil and gas reserves, future cash flows and abandonment costs may be significantly
incorrect to 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. We also deleted the word substantially from the fifth sentence of
the applicable revised risk factor. We also expanded our risk factor Reserve replacement
may not offset depletion; |
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Item 2. Properties Summary of Natural Gas and Oil Reserve Data, revised to add
disclosures related to production, reserves, nature of our interest, location and status of
development for our principal fields. We also enhanced our disclosures relating to the
methodology used in the determination of proved reserves and the scope of the engineering
audit by our independent petroleum engineers (Huddleston & Co., Inc. Huddleston); |
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Item 7. Managements Discussion and Analysis of Financial Condition and results of
Operation Results of Operations, revised to indicate the direct operating expenses
included in the breakout of our Oil and Gas operating expenses table includes production
taxes. We also referenced our disclosures in our Critical Accounting Estimates and
Policies relating to the engineering audit and the preparation of reserve data to Item 2;
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Item 8. Financial Statements and Supplementary Data, revised to provide enhanced
disclosures relating to the methodology used in the determination of proved reserves and
the scope of the engineering audit by our independent petroleum engineers. |
Other than as specified above, this amendment does not modify or affect the financial
statements or the notes thereto in the Original 10-K. This amendment does not reflect events
occurring after the filing of the Original 10-K and does not modify or update the disclosures
therein in any way other than as required to reflect the amendments as described above and set
forth below. In accordance with Rule 12b-15 promulgated under the Securities Exchange Act of 1934,
the complete text of each affected item, as amended, is included herein. Unaffected items have not
been repeated in this amendment. Unless the statements indicate otherwise, as used in this
amendment, the terms Company, we, us and our refer collectively to Helix and its
subsidiaries.
Forward Looking Statements
The statements included or incorporated by reference in this amended Annual Report on Form
10-K for the year ended December 31, 2006 (this Annual Report) include forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included herein or incorporated herein by reference are
forward-looking statements. Included among forward-looking statements are, among other things:
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statements related to the volatility in commodity prices for oil and gas
and in the supply of and demand for oil and natural gas or the ability
to replace oil and gas reserves; |
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statements regarding our anticipated production volumes, results of
exploration, exploitation, development, acquisition or operations
expenditures and current or prospective reserve levels with respect to
any property or well; and |
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statements regarding any financing transactions or arrangements, or
ability to enter into such transactions; |
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statements relating to the construction or acquisition of vessels or
equipment and our proposed acquisition of any producing property or well
prospect, including statements concerning the engagement of any
engineering, procurement and construction contractor and any anticipated
costs related thereto; |
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statements that our proposed vessels, when completed, will have certain
characteristics or the effectiveness of such characteristics; |
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statements regarding projections of revenues, gross margin, expenses,
earnings or losses or other financial items; |
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statements regarding our business strategy, our business plans or any
other plans, forecasts or objectives, any or all of which are subject to
change; |
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statements regarding any Securities and Exchange Commission or other
governmental or regulatory inquiry or investigation; |
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statements regarding anticipated legislative, governmental, regulatory,
administrative or other public body actions, requirements, permits or
decisions; |
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statements regarding anticipated developments, industry trends,
performance or industry ranking relating to our services or any
statements related to the underlying assumptions related to any
projection or forward-looking statement; |
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statements related to environmental risks, drilling and operating risks,
or exploration and development risks and the ability of the combined
company to retain key members of its senior management and key
employees; |
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statements regarding general economic or political conditions, whether
internationally, nationally or in the regional and local market areas in
which we are doing business; |
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any other statements that relate to non-historical or future information. |
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 below.
All forward-looking statements attributable to us or persons acting on our behalf are expressly
qualified in their entirety by these risk factors. Forward-looking statements are only as of the
date they are made, and other than as required under the securities laws, we assume no obligation
to update or revise these forward-looking statements or provide reasons why actual results may
differ.
PART I
Item 1A. Risk Factors.
Shareholders should carefully consider the following risk factors in addition to the other
information contained herein. You should be aware that the occurrence of the events described in
these risk factors and elsewhere in this Annual Report could have a material adverse effect on our
business, results of operations and financial position.
Risks Relating to our Contracting Services Operations
Our contracting services operations are adversely affected by low oil and gas prices and by the
cyclicality of the oil and gas industry.
Our contracting services operations are substantially dependent upon the condition of the oil
and gas industry and, in particular, the willingness of oil and gas companies to make capital
expenditures for offshore exploration, drilling and production operations. The level of capital
expenditures generally depends on the prevailing view of future oil and gas prices, which are
influenced by numerous factors affecting the supply and demand for oil and gas, including, but not
limited to:
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worldwide economic activity; |
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demand for oil and natural gas, especially in the United States, China and India; |
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economic and political conditions in the Middle East and other oil-producing regions; |
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actions taken by the Organization of Petroleum Exporting Countries (OPEC); |
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the availability and discovery rate of new oil and natural gas reserves in offshore areas; |
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the cost of offshore exploration for and production and transportation of oil and gas; |
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the ability of oil and natural gas companies to generate funds or otherwise obtain
external capital for exploration, development and production operations; |
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the sale and expiration dates of offshore leases in the United States and overseas; |
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the discovery rate of new oil and gas reserves in offshore areas; |
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technological advances affecting energy exploration, production, transportation and
consumption; |
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weather conditions; |
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environmental and other governmental regulations, and |
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tax policies. |
The level of offshore construction activity improved somewhat in 2004 with the trend
continuing through 2006, following higher commodity prices from 2003 to 2006 and significant damage
sustained to the Gulf of Mexico infrastructure in Hurricanes Katrina and Rita in 2005. We cannot
assure you that activity levels will remain the same or increase. A sustained period of low
drilling and production activity or the return of lower commodity prices would likely have a
material adverse effect on our financial position, cash flows and results of operations.
The operation of marine vessels is risky, and we do not have insurance coverage for all risks.
Marine construction involves a high degree of operational risk. Hazards, such as vessels
sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in
marine operations. These hazards can cause personal injury or loss of life, severe damage to and
destruction of property and equipment, pollution or environmental damage and suspension of
operations. Damage arising from such occurrences may result in lawsuits asserting large claims. We
maintain such insurance protection as we deem prudent, including Jones Act employee coverage, which
is the maritime equivalent of workers compensation, and hull insurance on our vessels. We cannot
assure you that any such insurance will be sufficient or effective under all circumstances or
against all hazards to which we may be subject. A successful claim for which we are not fully
insured could have a material adverse effect on us. Moreover, we cannot assure you that we will be
able to maintain adequate insurance in the future at rates that we consider reasonable. As a result
of market conditions, premiums and deductibles for certain of our insurance policies have increased
substantially and could escalate further. In some instances, certain insurance could become
unavailable or available only for reduced amounts of coverage. For example, insurance carriers are
now requiring broad exclusions for losses due to war risk and terrorist acts and limitations for
wind storm damages. As construction activity expands into deeper water in the Gulf of Mexico and
other deepwater basins of the world and with the initial public offering of CDI, a greater
percentage of our revenues may be from deepwater construction projects that are larger and more
complex, and thus riskier, than shallow water projects. As a result, our revenues and profits are
increasingly dependent on our larger vessels. The current insurance on our vessels, in some cases,
is in amounts approximating book value, which could be less than replacement value. In the event of
property loss due to a catastrophic marine disaster, mechanical failure, collision or other event,
insurance may not cover a substantial loss of revenues, increased costs and other liabilities, and
therefore, the loss of any of our large vessels could have a material adverse effect on our
operating performance.
Our contracting business typically declines in winter, and bad weather in the Gulf or North Sea can
adversely affect our operations.
Marine operations conducted in the Gulf and North Sea are seasonal and depend, in part, on
weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the
summer and fall when weather conditions are favorable for offshore exploration, development and
construction activities. We typically have experienced our lowest utilization rates in the first
quarter. As is common in the industry, we typically bear the risk of delays caused by some adverse
weather conditions. Accordingly, our results in any one quarter are not necessarily indicative of
annual results or continuing trends.
If we bid too low on a turnkey contract, we suffer adverse economic consequences.
A significant amount of our projects are performed on a qualified turnkey basis where
described work is delivered for a fixed price and extra work, which is subject to customer
approval, is billed
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separately. The revenue, cost and gross profit realized on a turnkey contract can vary from
the estimated amount because of changes in offshore job conditions, variations in labor and
equipment productivity from the original estimates, and the performance of third parties such as
equipment suppliers. These variations and risks inherent in the marine construction industry may
result in our experiencing reduced profitability or losses on projects.
Delays or cost overruns in our construction projects could adversely affect our business or the
expected cash flows from these projects upon completion may not be timely or as high as expected.
We currently have the following significant construction projects in our contracting services
operations:
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the construction of a newbuild North Sea Vessel, the Well Enhancer; |
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the conversion of the Caesar into a deepwater pipelay asset; |
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the addition of a modular-based drilling system on the Q4000; and |
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the construction of a minimal floating production unit to be utilized on the Phoenix
field, the Helix Producer I, through a consolidated 50% owned variable interest entity. |
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:
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unforeseen quality or engineering problems; |
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work stoppages; |
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weather interference; |
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unanticipated cost increases; |
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delays in receipt of necessary equipment; and |
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inability to obtain the requisite permits or approvals. |
Significant delays could also have a material adverse effect on expected contract commitments
for these projects and our future revenues and cash flow. We will not receive any material
increase in revenue or cash flows from these assets until they are placed in service and customers
enter into binding arrangements for the assets, which can potentially be several months after the
construction or conversion projects are completed. Furthermore, we cannot assure you that
customer demand for these assets will be as high as currently anticipated, and, as a result, our
future cash flows may be adversely affected. In addition, new assets from third-parties may also
enter the market in the future and compete with us.
Risks Relating to our Oil and Gas Operations
Exploration and production of oil and natural gas is a high-risk activity and is subject to a
variety of factors that we cannot control.
Our Oil & Gas business is subject to all of the risks and uncertainties normally associated
with the exploration for and development and production of oil and natural gas, including
uncertainties as to the presence, size and recoverability of hydrocarbons. We may not encounter
commercially productive oil and natural gas reservoirs. We may not recover all or any portion of
our investment in new wells. The presence of unanticipated pressures or irregularities in
formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and
result in a total loss of our investment, which could have a material adverse effect on our
financial condition, results of operations and cash flows. In addition, we often are uncertain as
to the future cost or timing of drilling, completing and operating wells.
Projecting future natural gas and oil production is imprecise. Producing oil and gas
reservoirs eventually have declining production rates. Projections of production rates rely on
certain assumptions regarding historical production patterns in the area or formation tests for a
particular producing horizon. Actual production rates could differ materially from such
projections. Production rates depend on a number of additional factors, including commodity
prices, market demand and the political, economic and regulatory climate.
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Further, our drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including:
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unexpected drilling conditions; |
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title problems; |
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pressure or irregularities in formations; |
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equipment availability, failures or accidents; |
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adverse weather conditions; and |
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compliance with environmental and other governmental requirements, which may
increase our costs or restrict our activities. |
Natural gas and oil prices are volatile, which makes future revenue uncertain.
Our financial condition and results of operations depend in part on the prices we receive for
the oil and gas we produce. The market prices for oil and gas are subject to fluctuation in
response to events beyond our control, such as:
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supply of and demand for oil and gas; |
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market uncertainty; |
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worldwide political and economic instability; and |
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government regulations. |
Oil and gas prices have historically been volatile, and such volatility is likely to continue.
Our ability to estimate the value of producing properties for acquisition 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:
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our revenues; |
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financial condition; |
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results of operations; |
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our ability to increase production and grow reserves in an economically efficient manner; and |
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our access to capital. |
Our commodity price risk management related to some of our oil and gas production may reduce our
potential gains from increases in oil and gas prices.
Oil and gas prices can fluctuate significantly and have a direct impact on our revenues.
To manage our exposure to the risks inherent in such a volatile market, from time to time, we have
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, 2006 and 2005,
audited by our independent petroleum engineers. These reports rely upon various assumptions,
including assumptions required by the Securities and Exchange Commission, as to oil and gas prices,
drilling and operating expenses, capital expenditures, abandonment costs, taxes and availability of
funds. The process of estimating oil and gas reserves is complex, requiring significant decisions
and assumptions in
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the evaluation of available geological, geophysical, engineering and economic data for each
reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash
flows, development expenditures, operating and abandonment expenses and quantities of recoverable
oil and gas reserves may vary from those estimated in these reports. Any significant variance in
these assumptions could materially affect the estimated quantity and value of our proved reserves.
You should not assume that the present value of future net cash flows from our proved reserves
referred to in this Annual Report is the current market value of our estimated oil and gas
reserves. In accordance with Securities and Exchange Commission requirements, we base the estimated
discounted future net cash flows from our proved reserves on prices and costs on the date of the
estimate. Actual future prices and costs may differ materially from those used in the net present
value estimate. In addition, if costs of abandonment are materially greater than our estimates,
they could have an adverse effect on financial position, cash flows and results of operations.
Reserve replacement may not offset depletion.
Oil and gas properties are depleting assets. We replace reserves through acquisitions,
exploration and exploitation of current properties. Approximately 74% of our proved reserves at
December 31, 2006 are PUDs and PDNP. Further, our proved producing reserves at December 31, 2006
are expected to experience annual decline rates averaging nearly 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, 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:
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refuse to initiate exploration or development projects; |
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initiate exploration or development projects on a slower or faster schedule than we prefer; |
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due to their own liquidity and cash flow problems, delay the pace of drilling or
development; and/or |
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drill more wells or build more facilities on a project than we can afford, whether
on a cash basis or through financing, which may limit our participation in those
projects or limit the percentage of our revenues from those projects. |
The occurrence of any of the foregoing events could have a material adverse effect on our
anticipated exploration and development activities.
Government regulation may affect our ability to conduct operations, and the nature of our business
exposes us to environmental liability.
Numerous federal and state regulations affect our oil and gas operations. Current regulations
are constantly reviewed by the various agencies at the same time that new regulations are being
considered and implemented. In addition, because we hold federal leases, the federal government
requires us to comply with numerous additional regulations that focus on government contractors.
The regulatory burden upon the oil and gas industry increases the cost of doing business and
consequently affects our profitability.
Our operations are subject to a variety of national (including federal, state and local) and
international laws and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental departments issue rules and
regulations to implement and enforce such laws that are often complex and costly to comply with and
that carry
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substantial administrative, civil and possibly criminal penalties for failure to comply. Under
these laws and regulations, we may be liable for remediation or removal costs, damages and other
costs associated with releases of hazardous materials including oil into the environment, and such
liability may be imposed on us even if the acts that resulted in the releases were in compliance
with all applicable laws at the time such acts were performed.
We operate in foreign jurisdictions that have various types of governmental laws and
regulations relating to the discharge of oil or hazardous substances and the protection of the
environment. Pursuant to these laws and regulations, we could be held liable for remediation of
some types of pollution, including the release of oil, hazardous substances and debris from
production, refining or industrial facilities, as well as other assets we own or operate or which
are owned or operated by either our customers or our sub-contractors.
In addition, changes in the environmental laws and regulations, or claims for damages to
persons, property, natural resources or the environment, could result in substantial costs and
liabilities, and thus there can be no assurance that we will not incur significant environmental
compliance costs in the future. Such environmental liability could substantially reduce our net
income and could have a significant impact on our financial ability to carry out our oil and gas
operations.
Our oil and gas operations involve significant risks, and we do not have insurance coverage for all
risks.
Our oil and gas operations are subject to risks incident to the operation of oil and gas
wells, including, but not limited to, uncontrollable flows of oil, gas, brine or well fluids into
the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical
damage, pollution and other risks, any of which could result in substantial losses to us. We
maintain insurance against some, but not all, of the risks described above. As a result, any
damage not covered by our insurance could have a material adverse effect on our financial
condition, results of operations and cash flows.
Risks Relating to General Corporate Matters
We have higher levels of indebtedness after the acquisition of Remington in 2006.
As of December 31, 2006, we have approximately $1.5 billion of indebtedness outstanding. The
significant level of combined indebtedness may have an adverse effect on our future operations,
including:
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limiting our ability to obtain additional financing on satisfactory terms to fund our
working capital requirements, capital expenditures, acquisitions, investments, debt service
requirements and other general corporate requirements; |
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increasing our vulnerability to general economic downturns, competition and industry
conditions, which could place us at a competitive disadvantage compared to our competitors
that are less leveraged; |
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increasing our exposure to rising interest rates because a portion of our borrowings are
at variable interest rates; |
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reducing the availability of our cash flow to fund our working capital requirements,
capital expenditures, acquisitions, investments and other general corporate requirements
because we will be required to use a substantial portion of our cash flow to service debt
obligations; |
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limiting our flexibility in planning for, or reacting to, changes in our business and
the industry in which we operate; and |
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limiting our ability to expand our business through capital expenditures or pursuit of
acquisition opportunities due to negative covenants in senior secured credit facilities
that place annual and aggregate limitations on the types and amounts of investments that we
may make, and limit our ability to use proceeds from asset sales for purposes other than
debt repayment (except in certain circumstances where proceeds will be reinvested under
criteria defined by our credit agreements) . |
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If we fail to comply with the covenants and other restrictions in the agreements
governing our debt, it could lead to an event of default and the acceleration of our repayment of
outstanding debt. Our ability to comply with these covenants and other restrictions may be
affected by events beyond our control, including prevailing economic and financial conditions.
We may not be able to compete successfully against current and future competitors.
The businesses in which we operate are highly competitive. Several of our competitors are
substantially larger and have greater financial and other resources than we have. If other
companies relocate or acquire vessels for operations in the Gulf or the North Sea, levels of
competition may increase and our business could be adversely affected. In the exploration and
production business, some of the larger integrated companies may be better able to respond to
industry changes including price fluctuations, oil and gas demands, political change and government
regulations.
The loss of the services of one or more of our key employees, or our failure to attract and retain
other highly qualified personnel in the future, could disrupt our operations and adversely affect
our financial results.
Our industry has lost a significant number of experienced professionals over the years due to,
among other reasons, the volatility in commodity prices. Our continued success depends on the
active participation of our key employees. The loss of our key people could adversely affect our
operations. We believe that our success and continued growth are also dependent upon our ability to
attract and retain skilled personnel. We believe that our wage rates are competitive; however,
unionization or a significant increase in the wages paid by other employers could result in a
reduction in our workforce, increases in the wage rates we pay, or both. If either of these events
occurs for any significant period of time, our revenues and profitability could be diminished and
our growth potential could be impaired.
If we fail to effectively manage our growth, our results of operations could be harmed.
We have a history of growing through acquisitions of large assets and acquisitions of
companies. We must plan and manage our acquisitions effectively to achieve revenue growth and
maintain profitability in our evolving market. If we fail to effectively manage current and future
acquisitions, our results of operations could be adversely affected. Our growth has placed, and is
expected to continue to place, significant demands on our personnel, management and other
resources. We must continue to improve our operational, financial, management and legal/compliance
information systems to keep pace with the growth of our business.
We may need to change the manner in which we conduct our business in response to changes in
government regulations.
Our subsea construction, intervention, inspection, maintenance and decommissioning operations
and our oil and gas production from offshore properties, including decommissioning of such
properties, are subject to and affected by various types of government regulation, including
numerous federal, state and local environmental protection laws and regulations. These laws and
regulations are becoming increasingly complex, stringent and expensive to comply with, and
significant fines and penalties may be imposed for noncompliance. We cannot assure you that
continued compliance with existing or future laws or regulations will not adversely affect our
operations.
Certain provisions of our corporate documents and Minnesota law may discourage a third party from
making a takeover proposal.
In addition to the 55,000 shares of preferred stock issued to Fletcher International, Ltd.
under the First Amended and Restated Agreement dated January 17, 2003, but effective as of December
31, 2002, by and between Helix and Fletcher International, Ltd., our board of directors has the
authority, without any action by our shareholders, to fix the rights and preferences on up to
4,945,000 shares of undesignated preferred stock, including dividend, liquidation and voting
rights. In addition, our by-laws divide the board of directors into three classes. We are also
subject to certain anti-takeover provisions of the Minnesota Business Corporation Act. We also have
employment contracts with most of our senior officers that
8
require cash payments in the event of a change of control. Any or all of the provisions or
factors described above may have the effect of discouraging a takeover proposal or tender offer not
approved by management and the board of directors and could result in shareholders who may wish to
participate in such a proposal or tender offer receiving less for their shares than otherwise might
be available in the event of a takeover attempt.
Our operations outside of the United States subject us to additional risks.
Our operations outside of the United States are subject to risks inherent in foreign
operations, including, without limitation:
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the loss of revenue, property and equipment from expropriation, nationalization,
war, insurrection, acts of terrorism and other political risks; |
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increases in taxes and governmental royalties; |
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changes in laws and regulations affecting our operations; |
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renegotiation or abrogation of contracts with governmental entities; |
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changes in laws and policies governing operations of foreign-based companies; |
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currency restrictions and exchange rate fluctuations; |
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world economic cycles; |
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restrictions or quotas on production and commodity sales; |
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limited market access; and |
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other uncertainties arising out of foreign government sovereignty over our
international operations. |
In addition, laws and policies of the United States affecting foreign trade and taxation may
also adversely affect our international operations.
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:
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ready markets for oil and natural gas; |
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the proximity and capacity of pipelines and other transportation facilities; |
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fluctuating demand for crude oil and natural gas; |
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the availability and cost of competing fuels; and |
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the effects of foreign governmental regulation of oil and gas production and sales. |
Pipeline and processing facilities do not exist in certain areas of exploration and,
therefore, any actual sales of our production could be delayed for extended periods of time until
such facilities are constructed.
As the initial public offering of CDI common stock was completed, in the future, we may not have
the same access to services and equipment, as we had historically.
Although we have made arrangements to retain access to the services and equipment of CDI
through certain inter-company agreements, it is possible that we will not have the same access to
those services and equipment as we had historically, and as our ownership in CDI decreases over
time, our access to such equipment and services could be further diminished.
Item 2. Properties.
We own a fleet of 33 vessels (one of which was held-for-sale at December 31, 2006 and sold in
January 2007) and 31 ROVs and trenchers. We also lease one vessel. We believe that the market in
the Gulf of Mexico requires specially designed and/or equipped vessels to competitively deliver
subsea construction and well operations services. Eleven of our vessels have DP capabilities
specifically designed to respond to the deepwater market requirements. Fifteen of our vessels
(thirteen of which are based in the Gulf of Mexico) have the capability to provide saturation
diving services.
9
Divestitures in 2006
In December 2006, we contributed the assets of our Shelf Contracting segment into CDI, our
then wholly owned subsidiary. CDI subsequently completed an initial public offering selling
22,173,000 shares of its common stock, which, together with shares issued to CDI employees
immediately after the offering, reduced our ownership of CDI to 73.0%. CDI received net proceeds of
$264.4 million from its initial public offering. All of the net proceeds were distributed to us as
a dividend. In connection with the offering, CDI entered into a $250 million revolving credit
facility. In December 2006, Cal Dive borrowed $201 million under the facility and distributed $200
million of the proceeds to us as a dividend. See Note 3 Initial Public Offering of Cal Dive
International, Inc. in Item 8 for additional information.
Related to the Acergy acquisition, we entered into a consent order with the U.S. Department of
Justice pursuant to which we agreed to divest three assets: the Carrier, the Defender and a
portable saturation diving system acquired from Torch. As a result, these vessels were classified
as held for sale at December 31, 2005. In 2006, we sold the portable saturation diving system and
the Defender. As of December 31, 2006, the Carrier remained classified as held for sale. In
January 2007, the Carrier was sold to an unrelated third-party. No gains or losses were recognized
related to the sale.
Acquisitions in 2006
In January 2006, our wholly owned subsidiary, Vulcan Marine Technology LLC, acquired the
Caesar (formerly known as the Baron), a four year old mono-hull vessel originally built for the
cable lay market. The vessel was under charter to a third-party until mid January 2007. After the
completion of the charter, the vessel was in transit to a shipyard in China where we plan to
convert the vessel into a deepwater pipelay asset. The vessel is 485 feet long and already has a
state-of-the-art, class 2, dynamic positioning system. The conversion program will primarily
involve the installation of a conventional S lay pipelay system together with a main crane and a
significant upgrade to the accommodation capability. A conversion team has already been assembled
with a base at Rotterdam, the Netherlands, and the vessel is likely to enter service during the
second half of 2007. The estimated cost to acquire and convert the vessel will be approximately
$137.5 million. We have entered into an agreement with the third party currently leasing the
vessel, whereby the third party has an option to purchase up to 49% of Vulcan for consideration
totaling the proportionate share of the cost of the vessel plus the actual cost of conversion
(conversion cost is estimated to be $110.0 million). The third party must make all contributions
to Vulcan on or before March 31, 2007.
In January 2006, the DLB 801 was acquired from Acergy. Subsequent to our purchase of the DLB
801, we sold a 50% interest in the vessel in January 2006 for approximately $19.0 million. The
vessel is currently under a 10-year charter lease agreement with the purchaser of the 50% interest,
in which the purchaser has an option to purchase the remaining 50% interest in the vessel beginning
in January 2009. This lease was accounted for as an operating lease. In March 2006, we also
acquired the Kestrel from Acergy.
On July 1, 2006, we acquired 100% of Remington, an independent oil and gas exploration and
production company headquartered in Dallas, Texas, with operations concentrated in the onshore and
offshore regions of the Gulf Coast, for approximately $1.4 billion in cash and stock and the
assumption of $349.6 million of liabilities. The acquisition of Remington increased our oil and
gas properties by approximately $860 million.
In addition, in July 2006, we acquired the business of Singapore-based Fraser Diving
International Ltd for an aggregate purchase price of approximately $29.3 million, subject to
post-closing adjustments, and the assumption of $2.2 million of liabilities. FDI owns six portable
saturation diving systems and 15 surface diving systems that operate primarily in Southeast Asia,
the Middle East, Australia and the Mediterranean. Included in the purchase price is a payment of
$2.5 million made in December 2005 to FDI for the purchase of one of the portable saturation diving
systems. The acquisition was accounted for as a business combination with the acquisition price
allocated to the assets acquired and liabilities assumed based upon their estimated fair values.
All of the assets acquired from FDI are included in our Shelf Contracting segment.
10
In August 2006, we acquired a 100% working interest in the Typhoon oil field (Green Canyon
Blocks 236/237), the Boris oil field (Green Canyon Block 282) and the Little Burn oil field (Green
Canyon Block 238) for the assumption of certain decommissioning liabilities. We have received
suspension of production (SOP) approval from the MMS. We will also have farm-in rights on
five near by blocks where three prospects have been identified in the Typhoon mini-basin. Following
the acquisition of the Typhoon field and MMS approval, we renamed the field Phoenix. We
expect to deploy a minimal floating production system in mid-2008 in the Phoenix field (see below).
Further, in October 2006, we, along with Kommandor RØMØ A/S (Kommandor RØMØ), a Danish
corporation, formed Kommandor, LLC (Kommandor), a Delaware limited liability company, to convert
a ferry vessel into a dynamically-positioned minimal floating production system (see Production
Facilities below). Kommandor qualified as a variable interest entity (VIE) under FASB
Interpretation No. 46 Consolidation of Variable Interest Entities (FIN 46). We are the primary
beneficiary of Kommandor. As a result, we have consolidated the results of Kommandor at December
31, 2006.
Also in October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (Seatrac) for total
consideration of approximately $12.7 million (including $180,000 of transaction costs), with
approximately $9.1 million paid to existing shareholders and $3.4 million for subscription of new
Seatrac shares (see Note 6 Other Acquisitions in Item 8. Financial Statements and Supplementary
Data for a detailed discussion of Seatrac). We changed the name of the entity to Well Ops SEA Pty
Ltd.
In December 2006, we acquired a 100% working interest in the Camelot oil field in the North
Sea for the assumption of certain decommissioning liabilities totaling approximately $7.6 million.
At December 31, 2006, Camelot had proved reserves of approximately 24 Bcfe. We have commenced
existing field rejuvenation and expect first production in 2007. It is our intent to sell down to
a 50% working interest prior to additional drilling or other large capital investments being made
in the Camelot field area.
11
OUR VESSELS
Listing of Vessels, Barges and ROVs Related to Contracting Services Operations(1)
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Placed |
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DP or |
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Flag |
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in |
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Length |
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SAT |
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Anchor |
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Crane Capacity |
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State |
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Service(2) |
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(Feet) |
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Berths |
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Diving |
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Moored |
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(tons) |
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SHELF CONTRACTING (CAL DIVE INTERNATIONAL, INC.): |
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Pipelay |
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DLB 801(3) |
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Panama |
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1/2006 |
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351 |
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230 |
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Capable |
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Anchor |
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815 |
Brave |
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U.S. |
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11/2005 |
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275 |
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80 |
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Anchor |
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30 and 50 |
Rider |
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U.S. |
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11/2005 |
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275 |
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80 |
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Anchor |
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50 |
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Saturation Diving |
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5; 4.3; 92/43; |
DP DSV Eclipse |
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Bahamas |
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3/2002 |
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367 |
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109 |
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X |
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DP |
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20.4 A-Frame |
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40; 15 ; 10; |
DP DSV Kestrel |
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Vanuatu |
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9/2006 |
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323 |
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80 |
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X |
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DP |
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Hydralift HLR 308 |
DP DSV Mystic Viking |
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Bahamas |
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6/2001 |
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253 |
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60 |
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X |
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DP |
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50 |
DP MSV Uncle John |
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Bahamas |
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11/1996 |
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254 |
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102 |
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X |
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DP |
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2×100 |
DSV American Constitution |
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Panama |
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11/2005 |
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200 |
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46 |
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X |
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4 point |
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20.41 |
DSV Cal Diver I |
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U.S. |
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7/1984 |
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196 |
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40 |
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X |
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4 point |
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20 |
DSV Cal Diver II |
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U.S. |
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6/1985 |
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166 |
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32 |
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X |
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4 point |
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40 A-Frame |
DSV Carrier (4) |
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Vanuatu |
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270 |
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36 |
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Capable |
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4 point |
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DSV Midnight Star(5) |
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Vanuatu |
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6/2006 |
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197 |
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42 |
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4 point |
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20 and 40 |
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Surface Diving |
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American Diver |
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U.S. |
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11/2005 |
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105 |
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22 |
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American Liberty |
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U.S. |
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11/2005 |
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110 |
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22 |
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1.588 |
Cal Diver IV |
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U.S. |
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3/2001 |
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120 |
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24 |
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DSV American Star |
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U.S. |
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11/2005 |
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165 |
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30 |
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4 point |
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9.072 |
DSV American Triumph |
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U.S. |
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11/2005 |
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164 |
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32 |
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4 point |
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13.61 |
DSV American Victory |
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U.S. |
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11/2005 |
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165 |
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34 |
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4 point |
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9.072 |
DSV Cal Diver V |
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U.S. |
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9/1991 |
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166 |
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34 |
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4 point |
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20 A-Frame |
DSV Dancer |
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U.S. |
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3/2006 |
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173 |
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34 |
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4 point |
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30 |
DSV Mr. Fred |
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U.S. |
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3/2000 |
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166 |
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36 |
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4 point |
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25 |
Fox |
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U.S. |
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10/2005 |
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130 |
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42 |
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Mr. Jack |
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U.S. |
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1/1998 |
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120 |
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22 |
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10 |
Mr. Jim |
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U.S. |
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2/1998 |
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110 |
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19 |
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Polo Pony |
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U.S. |
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3/2001 |
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110 |
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25 |
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Sterling Pony |
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U.S. |
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3/2001 |
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110 |
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25 |
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White Pony |
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U.S. |
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3/2001 |
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116 |
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25 |
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CONTRACTING SERVICES: |
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Pipelay |
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Caesar(6) |
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Vanuatu |
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1/2006 |
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482 |
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220 |
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DP |
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300 and 36 |
Express |
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Vanuatu |
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8/2005 |
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520 |
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132 |
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DP |
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500 and 120 |
Intrepid |
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Bahamas |
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8/1997 |
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381 |
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50 |
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DP |
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400 |
Talisman |
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U.S. |
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11/2000 |
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195 |
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14 |
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Well Operations |
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160 and 360; 600 |
Q4000(7) |
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U.S. |
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4/2002 |
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312 |
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135 |
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Capable |
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DP |
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Derrick |
Seawell |
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U.K. |
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7/2002 |
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368 |
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129 |
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X |
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DP |
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130 |
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Robotics |
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27 ROVs and 4 Trenchers(8) |
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Various |
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Northern Canyon(9) |
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Bahamas |
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6/2002 |
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276 |
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58 |
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DP |
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50 |
12
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(1) |
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Under government regulations and our insurance policies, we are required to maintain our
vessels in accordance with standards of seaworthiness and safety set by government
regulations and classification organizations. We maintain our fleet to the standards for
seaworthiness, safety and health set by the American Bureau of Shipping, or ABS, Bureau
Veritas, or BV, Det Norske Veritas, or DNV, Lloyds Register of Shipping, or Lloyds, and the
U.S. Coast Guard, or USCG. The ABS, BV, DNV and Lloyds are classification societies used by
ship owners to certify that their vessels meet certain structural, mechanical and safety
equipment standards. |
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(2) |
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Represents the date we placed the vessel in service and not the date of commissioning. |
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(3) |
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The DLB 801 was purchased in January 2006 and a 50% interest in the vessel was
subsequently sold to an unaffiliated purchaser that same month. The vessel is now under a
10-year charter lease agreement with the purchaser of the 50% interest. The charter lease
agreement includes an option by the purchasers to purchase our 50% interest in the vessel
beginning in January 2009. |
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(4) |
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Held for sale at December 31, 2006. The vessel was sold in January 2007. |
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(5) |
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Expected to be converted in the second or third quarter of 2007 to full saturation
diving capabilities. |
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(6) |
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Currently under conversion into a deepwater pipelay asset by late 2007. |
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(7) |
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Expected to add drilling capabilities on the vessel in mid-2007. |
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(8) |
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Average age of our fleet of ROVs and trenchers is approximately 4.01 years. |
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(9) |
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Leased. |
The following table details the average utilization rate for our vessels by category
(calculated by dividing the total number of days the vessels in this category generated revenues by
the total number of calendar days in the applicable period) for the years ended December 31, 2006,
2005 and 2004:
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Year Ended December 31, |
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2006 |
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2005 |
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2004 |
Contracting Services: |
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Pipelay |
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86 |
% |
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86 |
% |
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72 |
% |
Well operations |
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81 |
% |
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84 |
% |
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80 |
% |
ROVs |
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71 |
% |
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69 |
% |
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51 |
% |
Shelf Contracting |
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84 |
% |
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65 |
% |
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52 |
% |
We incur routine drydock, inspection, maintenance and repair costs pursuant to Coast
Guard regulations and in order to maintain our vessels in class under the rules of the applicable
class society. In addition to complying with these requirements, we have our own vessel maintenance
program that we believe permits us to continue to provide our customers with well maintained,
reliable vessels. In the normal course of business, we charter in other vessels on a short-term
basis, such as tugboats, cargo barges, utility boats and dive support vessels. The Q4000 is subject
to a mortgage that secures the MARAD financing guarantees as described in Item 8. Financial
Statements and Supplementary Data Note 10 Long-term Debt.
13
SUMMARY OF NATURAL GAS AND OIL RESERVE DATA
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 (140 fields as of December 31, 2006). 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) 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 performed 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 83% of the total
discounted future net revenues. Huddleston audited approximately 81% of our total reserve base in
the United States, including what was deemed to be the most valuable properties. Huddleston
audited 76% of proved developed reserves and 85% of the proved undeveloped reserves totaling 81% 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.
14
The table below sets forth information, as of December 31, 2006, 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.
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As of December 31, 2006 |
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Proved |
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Proved |
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|
|
Developed |
|
Undeveloped |
|
Total Proved |
|
|
Reserves |
|
Reserves |
|
Reserves |
United States: |
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf) |
|
|
156 |
|
|
|
138 |
|
|
|
294 |
|
Oil (MMBbls) |
|
|
13 |
|
|
|
23 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Bcfe) |
|
|
236 |
|
|
|
276 |
|
|
|
512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom: |
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf) |
|
|
|
|
|
|
24 |
|
|
|
24 |
|
Oil (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Bcfe) |
|
|
|
|
|
|
24 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf) |
|
|
156 |
|
|
|
162 |
|
|
|
318 |
|
Oil (MMBbls) |
|
|
13 |
|
|
|
23 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Bcfe) |
|
|
236 |
|
|
|
300 |
|
|
|
536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For additional information regarding estimates of oil and gas reserves, including
estimates of proved and proved developed reserves, the standardized measure of discounted future
net cash flows, and the changes in discounted future net cash flows, see Item 8. Financial
Statements and Supplementary Data Note 20 Supplemental Oil and Gas Disclosures.
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, 2006, 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. This is our only oil and gas property in the United Kingdom.
15
Our U.S. operations accounted for 100% of our 2006 production and approximately 96% of total
proved reserves at December 31, 2006 (74% of such total reserves are PUDs and PDNP). Further, our
proved producing reserves at December 31, 2006 are expected to experience annual decline rates
averaging nearly 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, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
Net Proved |
|
2006 Net |
|
|
|
|
|
Expected |
|
|
Development |
|
Reserves |
|
Reserves Mix |
|
Production |
|
Average |
|
First |
|
|
Location |
|
(Bcfe) |
|
Oil% |
|
Gas % |
|
(Bcfe) |
|
WI% |
|
Production |
United States Offshore: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deepwater |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phoenix(1) |
|
U.S. GOM |
|
|
47 |
|
|
|
79 |
% |
|
|
21 |
% |
|
|
|
|
|
|
100 |
% |
|
|
2008 |
|
Tiger(2) |
|
U.S. GOM |
|
|
13 |
|
|
|
|
|
|
|
100 |
% |
|
|
|
|
|
|
40 |
% |
|
Producing |
Gunnison(3) |
|
U.S. GOM |
|
|
31 |
|
|
|
46 |
% |
|
|
54 |
% |
|
|
10 |
|
|
|
19 |
% |
|
Producing |
Bass Lite(4) |
|
U.S. GOM |
|
|
18 |
|
|
|
|
|
|
|
100 |
% |
|
|
|
|
|
|
17.5 |
% |
|
|
2008 |
|
Devils Island(5) |
|
U.S. GOM |
|
|
21 |
|
|
|
73 |
% |
|
|
27 |
% |
|
|
|
|
|
|
94 |
% |
|
|
2008 |
|
Outer Continental Shelf |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East Cameron 346 |
|
U.S. GOM |
|
|
43 |
|
|
|
80 |
% |
|
|
20 |
% |
|
|
3 |
|
|
|
75 |
% |
|
Producing |
West Cameron 170 |
|
U.S. GOM |
|
|
25 |
|
|
|
28 |
% |
|
|
72 |
% |
|
|
1 |
|
|
|
55 |
% |
|
Producing |
South Marsh Island 130 |
|
U.S. GOM |
|
|
16 |
|
|
|
72 |
% |
|
|
28 |
% |
|
|
6 |
|
|
|
100 |
% |
|
Producing |
South Timbalier 86/63 |
|
U.S. GOM |
|
|
24 |
|
|
|
47 |
% |
|
|
53 |
% |
|
|
3 |
|
|
|
95 |
% |
|
Producing |
United States Onshore: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parker Creek |
|
Mississippi |
|
|
17 |
|
|
|
99 |
% |
|
|
1 |
% |
|
|
1 |
|
|
|
67 |
% |
|
Producing |
United Kingdom Offshore(6) |
|
UK Offshore |
|
|
24 |
|
|
|
|
|
|
|
100 |
% |
|
|
|
|
|
|
100 |
% |
|
|
2007 |
|
|
|
|
(1) |
|
Green Canyon blocks 236, 237, 238 and 282. |
|
(2) |
|
Green Canyon block 195. |
|
(3) |
|
An outside operated property comprised of Garden Banks blocks 625, 667, 668 and 669. |
|
(4) |
|
Atwater Valley block 426. |
|
(5) |
|
Garden Banks block 344. |
|
(6) |
|
Consists of our only property in the United Kingdom, Camelot. |
United States Offshore
Deepwater
We have proved reserves of approximately 130 Bcfe in five fields in the Gulf of Mexico
Deepwater which comprised approximately 24% of our total proved reserves as of December 31, 2006.
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 52% of our Deepwater proved reserves (approximately 13%
of total proved reserves). Gunnison has been producing since December 2003. The Tiger field began
production in late December 2006. Our net production in
Deepwater totaled approximately ten Bcfe
in 2006. We continue to be active in Deepwater with an ongoing exploration and development program.
Outer Continental Shelf
We have proved reserves of approximately 358 Bcfe in over 100 fields in the Gulf of Mexico on
the OCS which comprised approximately 67% of total proved reserves as of December 31, 2006. Our
net production on the OCS totaled approximately 38 Bcfe in 2006. 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 12% of OCS reserves (approximately 8% of total proved reserves). No other individual
OCS field comprised over 5% of total proved reserves. We are the operator of 52% 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 over 20 wells on the OCS in 2007.
16
United States Onshore
We have proved reserves of approximately 24 Bcfe in over 20 onshore fields in Mississippi,
Alabama, Louisiana and Texas, with net production totaling approximately one Bcfe in 2006. Our U.S.
onshore proved reserves comprised approximately 4% of total proved reserves as of December 31,
2006. The working interests in our onshore properties range from 7% to 94%. We are not the
operator of most of the onshore fields. One onshore non-operated field (Parker Creek) in
Mississippi comprised over 70% of our U.S. onshore reserves, but only approximately 3% of our total
proved reserves. There are no significant developments scheduled for the onshore fields.
United Kingdom Offshore
In December 2006, we acquired the Camelot field (100%), located in the North Sea. This is our
only oil and gas property in the United Kingdom.
Production, Price and Cost Data
Production, price and cost data for our oil and gas operations in the United States are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf) |
|
|
28 |
|
|
|
18 |
|
|
|
26 |
|
Oil (MMBbls) |
|
|
3 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
Total (Bcfe) |
|
|
48 |
|
|
|
33 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices realized (including hedges): |
|
|
|
|
|
|
|
|
|
|
|
|
Gas (per Mcf) |
|
$ |
7.86 |
|
|
$ |
8.08 |
|
|
$ |
5.76 |
|
Oil (per Bbl) |
|
$ |
60.41 |
|
|
$ |
49.15 |
|
|
$ |
33.92 |
|
Total (per Mcfe) |
|
$ |
8.79 |
|
|
$ |
8.13 |
|
|
$ |
5.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average production cost per Mcfe |
|
$ |
1.85 |
|
|
$ |
1.71 |
|
|
$ |
0.95 |
|
Average depletion and amortization per Mcfe |
|
$ |
2.79 |
|
|
$ |
2.14 |
|
|
$ |
1.66 |
|
As we acquired Camelot in December 2006 (which was not then producing), we had no oil and
gas production in the United Kingdom in 2006.
Productive Wells
The number of productive oil and gas wells in which we held interest as of December 31, 2006
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Wells |
|
Gas Wells |
|
Total Wells |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
United States Offshore |
|
|
145 |
|
|
|
107 |
|
|
|
155 |
|
|
|
71 |
|
|
|
300 |
|
|
|
178 |
|
United States Onshore |
|
|
24 |
|
|
|
8 |
|
|
|
75 |
|
|
|
15 |
|
|
|
99 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
169 |
|
|
|
115 |
|
|
|
230 |
|
|
|
86 |
|
|
|
399 |
|
|
|
201 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
17
The following table summarizes non-producing wells as of December 31, 2006. Included in
non-producing wells are productive wells awaiting additional action, pipeline connections or
shut-in for various reasons.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Wells |
|
Gas Wells |
|
Total Wells |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Not producing (shut-in) |
|
|
267 |
|
|
|
205 |
|
|
|
299 |
|
|
|
141 |
|
|
|
566 |
|
|
|
346 |
|
Developed and Undeveloped Acreage
The developed and undeveloped acreage (including both leases and concessions) that we held at
December 31, 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped |
|
|
Developed |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore |
|
|
625,100 |
|
|
|
393,870 |
|
|
|
711,189 |
|
|
|
378,731 |
|
Onshore |
|
|
9,470 |
|
|
|
6,956 |
|
|
|
20,914 |
|
|
|
7,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States |
|
|
634,570 |
|
|
|
400,826 |
|
|
|
732,103 |
|
|
|
385,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom offshore |
|
|
34,842 |
|
|
|
34,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
669,412 |
|
|
|
435,668 |
|
|
|
732,103 |
|
|
|
385,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed acreage is acreage spaced or assignable to productive wells. A gross acre is an
acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional
ownership working interests in gross acres equals one. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities of crude oil and
natural gas regardless of whether or not such acreage contains proved reserves. Included within
undeveloped acreage are those leased acres (held by production under the terms of a lease) that are
not within the spacing unit containing, or acreage assigned to, the productive well so holding such
lease. The current terms of our leases on undeveloped acreage are scheduled to expire as shown in
the table below (the terms of a lease may be extended by drilling and production operations
(acreage):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore |
|
Onshore |
|
Total |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
2007 |
|
|
156,732 |
|
|
|
70,872 |
|
|
|
3,708 |
|
|
|
2,490 |
|
|
|
160,440 |
|
|
|
73,362 |
|
2008 |
|
|
144,461 |
|
|
|
79,876 |
|
|
|
4,292 |
|
|
|
2,996 |
|
|
|
148,753 |
|
|
|
82,872 |
|
2009 |
|
|
114,729 |
|
|
|
74,682 |
|
|
|
1,470 |
|
|
|
1,470 |
|
|
|
116,199 |
|
|
|
76,152 |
|
2010 |
|
|
105,966 |
|
|
|
80,652 |
|
|
|
|
|
|
|
|
|
|
|
105,966 |
|
|
|
80,652 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
521,888 |
|
|
|
306,082 |
|
|
|
9,470 |
|
|
|
6,956 |
|
|
|
531,358 |
|
|
|
313,038 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling Activity
The following table shows the results of oil and gas wells drilled in the United States for
each of the years ended December 31, 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exploratory Wells |
|
Net Development Wells |
|
|
Productive |
|
Dry |
|
Total |
|
Productive |
|
Dry |
|
Total |
Year ended December 31, 2006 |
|
|
6.5 |
|
|
|
2.1 |
|
|
|
8.6 |
|
|
|
4.6 |
|
|
|
|
|
|
|
4.6 |
|
Year ended December 31, 2005 |
|
|
0.4 |
|
|
|
|
|
|
|
0.4 |
|
|
|
1.2 |
|
|
|
|
|
|
|
1.2 |
|
Year ended December 31, 2004 |
|
|
1.3 |
|
|
|
|
|
|
|
1.3 |
|
|
|
1.1 |
|
|
|
|
|
|
|
1.1 |
|
As we acquired Camelot in December 2006, no wells were drilled in the United Kingdom in
2006.
18
A productive well is an exploratory or development well that is not a dry hole. A dry hole is
an exploratory or development well determined to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to
find a new reservoir in a field previously found to be productive of oil or gas in another
reservoir, or to extend a known reservoir. A development well, for purposes of the table above and
as defined in the rules and regulations of the SEC, is a well drilled within the proved area of a
crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
The number of wells drilled refers to the number of wells completed at any time during the
respective year, regardless of when drilling was initiated. Completion refers to the installation
of permanent equipment for the production of crude oil or natural gas, or in the case of a dry
hole, to the reporting of abandonment to the appropriate agency.
At December 31, 2006, our oil and gas operations were drilling 2 gross (0.6 net) development
wells and 6 gross (4 net) exploration wells, and 0.4 net suspended exploratory wells. These wells
are located in the Gulf of Mexico. The drilling cost to us for these wells will be approximately
$104.2 million if all are dry and approximately $163.4 million if all are completed as producing
wells.
PRODUCTION FACILITIES
Through our interest in Deepwater Gateway, L.L.C., a limited liability company in which
Enterprise Products Partners L.P. is the other member, we own a 50% interest in the Marco Polo TLP,
which was installed on Green Canyon Block 608 in 4,300 feet of water. Deepwater Gateway, L.L.C.
was formed to construct, install and own the Marco Polo TLP in order to process production from
Anadarko Petroleum 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 will own the Independence Hub platform, a 105 foot deep draft,
semi-submersible platform to be located in Mississippi Canyon block 920 in a water depth of 8,000
feet that will serve as a regional hub for natural gas production from multiple ultra-Deepwater
fields in the previously untapped eastern Gulf of Mexico. Installation of the platform is scheduled
for the first quarter of 2007 and first production is expected in mid-2007. The Independence Hub
facility will be capable of processing 1 billion cubic feet (bcf) per day of gas.
We own a 20% interest in the Gunnison truss spar facility, together with the operator
Kerr-McGee Oil & Gas Corporation, which owns a 50% interest, and Nexen, Inc., which owns the
remaining 30% interest. The Gunnison spar, which is moored in 3,150 feet of water and located on
Garden Banks Block 668, has daily production capacity of 40,000 barrels of oil and 200 million
cubic feet of gas. This facility is designed with excess capacity to accommodate production from
satellite prospects in the area.
Further, in October 2006, we invested $15 million for a 50% interest in Kommandor to convert a
ferry vessel into a dynamically-positioned minimal floating production system. Upon completion of
the initial conversion, this vessel will be leased under a bareboat charter to us for further
conversion and subsequent use as a floating production system in the Deepwater Gulf of Mexico,
initially for the Phoenix field. Conversion of the vessel is expected to be completed in two
phases. The first phase is expected to be completed by the end of 2007 for approximately $60
million. The second phase of the conversion is expected to be completed by mid-2008. Estimated
cost of conversion for the second phase is approximately $100 million, of which we expect to fund
100%.
19
FACILITIES
Our corporate headquarters are located at 400 N. Sam Houston Parkway E., Suite 400, Houston,
Texas. Our primary subsea and marine services operations are based in Port of Iberia, Louisiana. We
own the Aberdeen (Dyce), Scotland facility. All of our other facilities are leased.
Properties and Facilities Summary
|
|
|
|
|
Location |
|
Function |
|
Size |
Houston, Texas
|
|
Helix Energy Solutions Group, Inc.
|
|
85,000 square feet |
|
|
Corporate Headquarters, Project Management,
and Sales Office |
|
|
|
|
Cal Dive International, Inc. |
|
|
|
|
Corporate Headquarters, Project Management,
and Sales Office |
|
|
|
|
Energy Resource Technology GOM, Inc. |
|
|
|
|
Corporate Headquarters |
|
|
|
|
Well Ops Inc. |
|
|
|
|
Corporate Headquarters, Project Management,
and Sales Office |
|
|
|
|
Kommandor LLC(1) |
|
|
|
|
Corporate Headquarters |
|
|
|
|
|
|
|
Houston, Texas
|
|
Canyon Offshore, Inc.
|
|
27,000 square ft. |
|
|
Corporate, Management and Sales Office |
|
|
|
|
|
|
|
Dallas, Texas
|
|
Energy Resource Technology GOM, Inc.
|
|
25,000 square ft. |
|
|
Dallas Office |
|
|
|
|
|
|
|
Port of Iberia, Louisiana
|
|
Cal Dive International, Inc.(2)
|
|
23 acres |
|
|
Operations, Offices and Warehouse
|
|
(Buildings: 68,602 square feet) |
|
|
|
|
|
Fourchon, Louisiana
|
|
Cal Dive International, Inc. (2)
|
|
10 acres |
|
|
Marine, Operations, Living Quarters
|
|
(Buildings: 2,300 square feet) |
|
|
|
|
|
New Orleans, Louisiana
|
|
Cal Dive International, Inc. (2)
|
|
2,724 square feet |
|
|
Sales Office |
|
|
|
|
|
|
|
Dubai, United Arab Emirates
|
|
Cal Dive International, Inc. (2)
|
|
12,916 square feet |
|
|
Sales Office and Warehouse |
|
|
|
|
|
|
|
Aberdeen (Dyce), Scotland
|
|
Well Ops (U.K.) Limited
|
|
3.9 acres |
|
|
Corporate Offices and Operations
|
|
(Building: 42,463 square ft.) |
|
|
Canyon Offshore Limited |
|
|
|
|
Corporate Offices, Operations and Sales Office |
|
|
|
|
|
|
|
Aberdeen (Westhill), Scotland
|
|
Helix RDS Limited
|
|
11,333 square ft. |
|
|
Corporate Offices |
|
|
|
|
ERT (UK) Limited |
|
|
|
|
Corporate Offices |
|
|
|
|
|
|
|
London, England
|
|
Helix RDS Limited
|
|
3,365 square ft. |
|
|
Corporate Offices |
|
|
|
|
|
|
|
Kuala Lumpur, Malaysia
|
|
Helix RDS Sdn Bhd
|
|
2,227 square ft. |
|
|
Corporate Offices |
|
|
|
|
|
|
|
Perth, Australia
|
|
Cal Dive International, Inc. (2)
|
|
28,738 square feet |
|
|
Operations, Offices and Project Management |
|
|
|
|
|
|
|
Perth, Australia
|
|
Well Ops SEA Pty Ltd(3)
|
|
1.0 acre |
|
|
Corporate Offices
|
|
(Building: 12,040 square feet) |
20
|
|
|
|
|
Location |
|
Function |
|
Size |
Perth, Australia
|
|
Helix RDS Pty Ltd
|
|
8,202 square ft. |
|
|
Corporate Offices |
|
|
|
|
Helix ESG Pty Ltd. |
|
|
|
|
Corporate Offices |
|
|
|
|
|
|
|
Rotterdam, The Netherlands
|
|
Helix Energy Solutions BV
|
|
6,620 square ft. |
|
|
Corporate Offices |
|
|
|
|
|
|
|
Singapore
|
|
Cal Dive International, Inc. (2)
|
|
29,772 square feet |
|
|
Marine, Operations, Offices, Project |
|
|
|
|
Management and Warehouse |
|
|
|
|
|
|
|
Singapore
|
|
Canyon Offshore International Corp
|
|
13,180 square ft. |
|
|
Corporate, Operations and Sales |
|
|
|
|
Well Ops PTE Ltd |
|
|
|
|
Corporate Headquarters |
|
|
|
|
|
(1) |
|
Kommandor LLC is a joint venture in which we owned 50% at December 31, 2006. Kommandor
is included in our consolidated results as of December 31, 2006. |
|
(2) |
|
Cal Dive International, Inc. is our Shelf Contracting subsidiary, of which we owned
73.0% at December 31, 2006. |
|
(3) |
|
At December 31, 2006, we owned 58% of Well Ops SEA Pty Ltd. |
21
PART II
Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operation
The following management discussion and analysis should be read in conjunction with our
historical consolidated financial statements and their notes included elsewhere in this report.
This discussion contains forward-looking statements that reflect our current views with respect to
future events and financial performance. Our actual results may differ materially from those
anticipated in these forward-looking statements as a result of certain factors, such as those set
forth under Risk Factors and elsewhere in this report.
Executive Summary
Our Business
We are an international offshore energy company that provides development solutions and other
key services to the open energy market as well as to our own oil and gas properties. Our oil and
gas business is a prospect generation, exploration, development and production company. Employing
our own key services and methodologies we seek to lower finding and development (F&D) costs,
relative to industry norms.
Industry Overview and Major Influences
The offshore oil and gas industry originated in the early 1950s as producers began to explore
and develop the new frontier of offshore fields. The industry has grown significantly since the
1970s with service providers taking on greater roles on behalf of the producers. Industry standards
were established during this period largely in response to the emergence of the North Sea as a
major province leading the way into a new hostile frontier. The methodology of these standards was
driven by the requirement of mitigating the risk of developing relatively large reservoirs in a
then challenging environment. These standards are still largely adhered to today for all
developments even if they are small and the frontier is more understood. There are factors we
believe will influence the industry in the coming years: (1) Increasing world demand for oil and
natural gas; (2) global production rates peaking; (3) globalization of the natural gas market; (4)
increasing number of mature and small reservoirs; (5) increasing ratio of contribution to global
production from marginal fields; (6) increasing offshore activity; and (7) increasing number of
subsea developments.
Our business is substantially dependent upon the condition of the oil and natural gas industry
and, in particular, the willingness of oil and natural gas companies to make capital expenditures
for offshore exploration, drilling and production operations. The level of capital expenditure
generally depends on the prevailing views of future oil and natural gas prices, which are
influenced by numerous factors, including but not limited to:
|
|
|
worldwide economic activity; |
|
|
|
|
demand for oil and natural gas, especially in the United States, China and India; |
|
|
|
|
economic and political conditions in the Middle East and other oil-producing regions; |
|
|
|
|
actions taken by the Organization of Petroleum Exporting Countries (OPEC); |
|
|
|
|
the availability and discovery rate of new oil and natural gas reserves in offshore areas; |
|
|
|
|
the cost of offshore exploration for and production and transportation of oil and gas; |
|
|
|
|
the ability of oil and natural gas companies to generate funds or otherwise obtain
external capital for exploration, development and production operations; |
|
|
|
|
the sale and expiration dates of offshore leases in the United States and overseas; |
|
|
|
|
the discovery rate of new oil and gas reserves in offshore areas; |
|
|
|
|
technological advances affecting energy exploration production transportation and consumption; |
|
|
|
|
weather conditions; |
|
|
|
|
environmental and other governmental regulations; and |
|
|
|
|
tax policies. |
22
Activity Summary
Over the last few years we continued to evolve the Helix model by completing a variety of
transactions and events which have had, and we believe will continue to have, significant impacts
on our results of operations and financial condition. In 2005, we substantially increased the size
of our Shelf Contracting fleet and Deepwater pipelay fleet through the acquisition of assets from
Torch and Acergy for a combined purchase price of $210.2 million. We also acquired a significant
mature property package on the Gulf of Mexico OCS from Murphy Oil Corporation for $163.5 million
cash and assumption of abandonment liability of $32 million. Finally, we established our Reservoir
and Well Tech Services group through the acquisition of Helix Energy Limited (Helix RDS) for
$32.7 million. In 2006, we acquired Remington, an exploration, development and production company,
for approximately $1.4 billion in cash and stock and the assumption of $349.6 million of
liabilities. We changed our name from Cal Dive International, Inc. to Helix Energy Solutions
Group, Inc., leaving the Cal Dive name in our diving subsidiary, and in December 2006 completed a
carve-out IPO of that company selling a 26.5% stake receiving pre-tax net proceeds of $264.4
million from CDI and a pre-tax dividend of $200 million from CDIs revolver. We acquired the
Caesar, a 485 foot cable lay vessel which we intend to convert into a Deepwater pipelay asset
(total acquisition plus estimated conversion cost is $137.5 million). We also acquired a 100%
interest in the Phoenix field (formerly known as Typhoon) where we expect to deploy a minimal
floating production system in mid-2008. We also expanded our subsea well intervention services in
Australia through the acquisition of 58% of Seatrac. Finally, we moved our stock listing from
Nasdaq (HELX) to the New York Stock Exchange (HLX) in July 2006.
In February 2007, we announced an update on drilling activity at our 100% owned Noonan
prospect on Garden Banks Block 506 in 2,700 feet of water. Since operations commenced in October
2006, we have completed the drilling of an exploratory well and two appraisal sidetracks.
Formation evaluation from wireline logs, pressure analysis and sidewall cores have successfully
delineated our reservoir for completion of the well.
Results of Operations
Our operations are conducted through the following lines of businesses: contracting services
operations and oil and gas operations. We have disaggregated our contracting services operations
into three reportable segments in accordance with SFAS 131. As a result, our reportable segments
consist of the following: Contracting Services (formerly known as Deepwater Contracting), Shelf
Contracting, Oil and Gas (formerly known as Oil and Gas Production) and Production Facilities.
Contracting Services operations include services such as deepwater pipelay, well operations,
robotics and reservoir and well tech services. Shelf Contracting operations consist of assets
deployed primarily for diving-related activities and shallow water construction. See Item 8.
Financial Statements and Supplementary Data Note 3 Initial Public Offering of Cal Dive
International, Inc. for discussion of initial public offering of CDI common stock (represented by
the Shelf Contracting segment). All material intercompany transactions between the segments have
been eliminated in our consolidated results of operations.
23
Comparison of Years Ended 2006 and 2005
The following table details various financial and operational highlights for the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
Revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
485,246 |
|
|
$ |
328,315 |
|
|
$ |
156,931 |
|
Shelf Contracting |
|
|
509,917 |
|
|
|
223,211 |
|
|
|
286,706 |
|
Oil and Gas |
|
|
429,607 |
|
|
|
275,813 |
|
|
|
153,794 |
|
Intercompany elimination |
|
|
(57,846 |
) |
|
|
(27,867 |
) |
|
|
(29,979 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,366,924 |
|
|
$ |
799,472 |
|
|
$ |
567,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
138,516 |
|
|
$ |
69,381 |
|
|
$ |
69,135 |
|
Shelf Contracting |
|
|
222,530 |
|
|
|
71,215 |
|
|
|
151,315 |
|
Oil and Gas |
|
|
162,386 |
|
|
|
142,476 |
|
|
|
19,910 |
|
Intercompany elimination |
|
|
(8,024 |
) |
|
|
|
|
|
|
(8,024 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
515,408 |
|
|
$ |
283,072 |
|
|
$ |
232,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
|
29 |
% |
|
|
21 |
% |
|
8 pts |
|
Shelf Contracting |
|
|
44 |
% |
|
|
32 |
% |
|
12 pts |
|
Oil and Gas |
|
|
38 |
% |
|
|
52 |
% |
|
(14) pts |
|
Total company |
|
|
38 |
% |
|
|
35 |
% |
|
3 pts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of vessels(1)/ Utilization(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelay |
|
|
3/86 |
% |
|
|
2/86 |
% |
|
|
|
|
Well operations |
|
|
2/81 |
% |
|
|
2/84 |
% |
|
|
|
|
ROVs |
|
|
32/71 |
% |
|
|
30/69 |
% |
|
|
|
|
Shelf Contracting |
|
|
25/84 |
% |
|
|
23/65 |
% |
|
|
|
|
|
|
|
(1) |
|
Represents number of vessels as of the end the period excluding acquired vessels prior to
their in-service dates, vessels taken out of service prior to their disposition and vessels
jointly owned with a third party. |
|
(2) |
|
Average vessel utilization rate is 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. |
Intercompany segment revenues during the years ended December 31, 2006 and 2005 were as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
Contracting Services |
|
$ |
42,585 |
|
|
$ |
26,431 |
|
|
$ |
16,154 |
|
Shelf Contracting |
|
|
15,261 |
|
|
|
1,436 |
|
|
|
13,825 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
57,846 |
|
|
$ |
27,867 |
|
|
$ |
29,979 |
|
|
|
|
|
|
|
|
|
|
|
24
Intercompany segment profit (which only relates to intercompany capital projects) during
the years ended December 31, 2006 and 2005 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
Contracting Services |
|
$ |
2,460 |
|
|
$ |
|
|
|
$ |
2,460 |
|
Shelf Contracting |
|
|
5,564 |
|
|
|
|
|
|
|
5,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
8,024 |
|
|
$ |
|
|
|
$ |
8,024 |
|
|
|
|
|
|
|
|
|
|
|
The following table details various financial and operational highlights related to our
oil and gas operations for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2006 |
|
|
2005 |
|
|
Decrease |
|
Oil and Gas information |
|
|
|
|
|
|
|
|
|
|
|
|
Oil production volume (MBbls) |
|
|
3,400 |
|
|
|
2,473 |
|
|
|
927 |
|
Oil sales revenue (in thousands) |
|
$ |
205,415 |
|
|
$ |
121,510 |
|
|
$ |
83,905 |
|
Average oil sales price per Bbl (excluding hedges) |
|
$ |
61.08 |
|
|
$ |
51.87 |
|
|
$ |
9.21 |
|
Average realized oil price per Bbl (including hedges) |
|
$ |
60.41 |
|
|
$ |
49.15 |
|
|
$ |
11.26 |
|
Increase in oil sales revenue due to: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in prices (in thousands) |
|
$ |
27,840 |
|
|
|
|
|
|
|
|
|
Change in production volume (in thousands) |
|
|
56,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total increase in oil sales revenue (in thousands) |
|
$ |
83,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas production volume (MMcf) |
|
|
27,949 |
|
|
|
18,137 |
|
|
|
9,812 |
|
Gas sales revenue (in thousands) |
|
$ |
219,674 |
|
|
$ |
146,591 |
|
|
$ |
73,083 |
|
Average gas sales price per mcf (excluding hedges) |
|
$ |
7.46 |
|
|
$ |
8.48 |
|
|
$ |
(1.02 |
) |
Average realized gas price per mcf (including hedges) |
|
$ |
7.86 |
|
|
$ |
8.08 |
|
|
$ |
(0.22 |
) |
Increase (decrease) in gas sales revenue due to: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in prices (in thousands) |
|
$ |
(4,018 |
) |
|
|
|
|
|
|
|
|
Change in production volume (in thousands) |
|
|
77,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total increase in gas sales revenue (in thousands) |
|
$ |
73,083 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe) |
|
|
48,349 |
|
|
|
32,975 |
|
|
|
15,374 |
|
Price per Mcfe |
|
$ |
8.79 |
|
|
$ |
8.13 |
|
|
$ |
0.66 |
|
25
Presenting the expenses of our Oil and Gas segment 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 this basis with barrels of oil converted to Mcfe at a ratio of one barrel to six
Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
Total |
|
|
Per Mcfe |
|
|
Total |
|
|
Per Mcfe |
|
Oil and gas operating expenses(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses(2) |
|
$ |
50,930 |
|
|
$ |
1.05 |
|
|
$ |
26,997 |
|
|
$ |
0.82 |
|
Workover |
|
|
11,462 |
|
|
|
0.24 |
|
|
|
9,668 |
|
|
|
0.29 |
|
Transportation |
|
|
3,174 |
|
|
|
0.07 |
|
|
|
3,814 |
|
|
|
0.12 |
|
Repairs and maintenance |
|
|
13,081 |
|
|
|
0.27 |
|
|
|
6,030 |
|
|
|
0.18 |
|
Overhead and company labor |
|
|
10,492 |
|
|
|
0.22 |
|
|
|
9,726 |
|
|
|
0.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
89,139 |
|
|
$ |
1.85 |
|
|
$ |
56,235 |
|
|
$ |
1.71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and amortization |
|
$ |
134,967 |
|
|
$ |
2.79 |
|
|
$ |
70,637 |
|
|
$ |
2.14 |
|
|
|
|
(1) |
|
Excludes exploration expense of $43.1 million and $6.5 million for the years ended
December 31, 2006 and 2005, respectively. Exploration expense is not a component of lease
operating expense. |
|
(2) |
|
Includes production taxes. |
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
26
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.
27
Comparison of Years Ended 2005 and 2004
The following table details various financial and operational highlights for the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2005 |
|
|
2004 |
|
|
(Decrease) |
|
Revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
328,315 |
|
|
$ |
197,688 |
|
|
$ |
130,627 |
|
Shelf Contracting |
|
|
223,211 |
|
|
|
126,546 |
|
|
|
96,665 |
|
Oil and Gas |
|
|
275,813 |
|
|
|
243,310 |
|
|
|
32,503 |
|
Intercompany elimination |
|
|
(27,867 |
) |
|
|
(24,152 |
) |
|
|
(3,715 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
799,472 |
|
|
$ |
543,392 |
|
|
$ |
256,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
69,381 |
|
|
$ |
11,142 |
|
|
$ |
58,239 |
|
Shelf Contracting |
|
|
71,215 |
|
|
|
25,516 |
|
|
|
45,699 |
|
Oil and Gas |
|
|
142,476 |
|
|
|
135,427 |
|
|
|
7,049 |
|
Intercompany elimination |
|
|
|
|
|
|
(173 |
) |
|
|
173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
283,072 |
|
|
$ |
171,912 |
|
|
$ |
111,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
|
21 |
% |
|
|
6 |
% |
|
15 pts |
|
Shelf Contracting |
|
|
32 |
% |
|
|
20 |
% |
|
12 pts |
|
Oil and Gas |
|
|
52 |
% |
|
|
56 |
% |
|
(4)pts |
|
Total company |
|
|
35 |
% |
|
|
32 |
% |
|
3 pts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of vessels(1)/ Utilization(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelay |
|
|
2/86 |
% |
|
|
1/72 |
% |
|
|
|
|
Well operations |
|
|
2/84 |
% |
|
|
2/80 |
% |
|
|
|
|
ROVs |
|
|
30/69 |
% |
|
|
22/51 |
% |
|
|
|
|
Shelf Contracting |
|
|
23/65 |
% |
|
|
17/52 |
% |
|
|
|
|
|
|
|
(1) |
|
Represents number of vessels as of the end the period excluding acquired vessels prior
to their in-service dates, vessels taken out of service prior to their disposition and
vessels jointly owned with a third party. |
|
(2) |
|
Average vessel utilization rate is 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. |
Intercompany segment revenues during the years ended December 31, 2005 and 2004 were as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2005 |
|
|
2004 |
|
|
(Decrease) |
|
Contracting Services |
|
$ |
26,431 |
|
|
$ |
22,246 |
|
|
$ |
4,185 |
|
Shelf Contracting |
|
|
1,436 |
|
|
|
1,906 |
|
|
|
(470 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
27,867 |
|
|
$ |
24,152 |
|
|
$ |
3,715 |
|
|
|
|
|
|
|
|
|
|
|
28
Intercompany segment profit (which only relates to intercompany capital projects) during
the years ended December 31, 2005 and 2004 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2005 |
|
|
2004 |
|
|
(Decrease) |
|
Contracting Services |
|
$ |
|
|
|
$ |
91 |
|
|
$ |
(91 |
) |
Shelf Contracting |
|
|
|
|
|
|
82 |
|
|
|
(82 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
173 |
|
|
$ |
(173 |
) |
|
|
|
|
|
|
|
|
|
|
The following table details various financial and operational highlights related to our
oil and gas operations for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Increase/ |
|
|
|
2005 |
|
|
2004 |
|
|
(Decrease) |
|
Oil and Gas information |
|
|
|
|
|
|
|
|
|
|
|
|
Oil production volume (MBbls) |
|
|
2,473 |
|
|
|
2,593 |
|
|
|
(120 |
) |
Oil sales revenue (in thousands) |
|
$ |
121,510 |
|
|
$ |
87,951 |
|
|
$ |
33,559 |
|
Average oil sales price per Bbl (excluding hedges) |
|
$ |
51.87 |
|
|
$ |
38.05 |
|
|
$ |
13.82 |
|
Average realized oil price per Bbl (including hedges) |
|
$ |
49.15 |
|
|
$ |
33.92 |
|
|
$ |
15.23 |
|
Increase (decrease) in oil sales revenue due to: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in prices (in thousands) |
|
$ |
37,664 |
|
|
|
|
|
|
|
|
|
Change in production volume (in thousands) |
|
|
(4,105 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total increase in oil sales revenue (in thousands) |
|
$ |
33,559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas production volume (MMcf) |
|
|
18,137 |
|
|
|
25,957 |
|
|
|
(7,820 |
) |
Gas sales revenue (in thousands) |
|
$ |
146,591 |
|
|
$ |
149,395 |
|
|
$ |
(2,804 |
) |
Average gas sales price per mcf (excluding hedges) |
|
$ |
8.48 |
|
|
$ |
5.77 |
|
|
$ |
2.71 |
|
Average realized gas price per mcf (including hedges) |
|
$ |
8.08 |
|
|
$ |
5.76 |
|
|
$ |
2.32 |
|
Increase (decrease) in gas sales revenue due to: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in prices (in thousands) |
|
$ |
42,078 |
|
|
|
|
|
|
|
|
|
Change in production volume (in thousands) |
|
|
(44,882 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total decrease in gas sales revenue (in thousands) |
|
$ |
(2,804 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe) |
|
|
32,975 |
|
|
|
41,515 |
|
|
|
(8,540 |
) |
Price per Mcfe |
|
$ |
8.13 |
|
|
$ |
5.72 |
|
|
$ |
2.41 |
|
29
Presenting the expenses of our Oil and Gas segment 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 this basis with barrels of oil converted to Mcfe at a ratio of one barrel to six
Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
Total |
|
|
Per Mcfe |
|
|
Total |
|
|
Per Mcfe |
|
Oil and gas operating expenses(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses(2) |
|
$ |
26,997 |
|
|
$ |
0.82 |
|
|
$ |
19,030 |
|
|
$ |
0.46 |
|
Workover |
|
|
9,668 |
|
|
|
0.29 |
|
|
|
3,111 |
|
|
|
0.07 |
|
Transportation |
|
|
3,814 |
|
|
|
0.12 |
|
|
|
3,898 |
|
|
|
0.09 |
|
Repairs and maintenance |
|
|
6,030 |
|
|
|
0.18 |
|
|
|
5,173 |
|
|
|
0.12 |
|
Overhead and company labor |
|
|
9,726 |
|
|
|
0.30 |
|
|
|
8,198 |
|
|
|
0.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
56,235 |
|
|
$ |
1.71 |
|
|
$ |
39,410 |
|
|
$ |
0.95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and amortization |
|
$ |
70,637 |
|
|
$ |
2.14 |
|
|
$ |
69,046 |
|
|
$ |
1.66 |
|
|
|
|
(1) |
|
Excludes exploration expense of $6.5 million for the year ended December 31, 2005. We
had no exploration expenses in 2004. Exploration expense is not a component of lease
operating expense. |
|
(2) |
|
Includes production taxes. |
Revenues. During the year ended December 31, 2005, our revenues increased 47% as
compared to the same period in 2004. Our Contracting Services revenues increase was due primarily
to improved market demand resulting in significantly improved utilization rates and contracting
pricing for all divisions within the segment (deepwater, well operations and ROVs). The Shelf
Contracting revenues increase was also due to improved market demand, much of which was the result
of damages sustained in Hurricanes Katrina and Rita. This resulted in significantly improved
utilization rates and contract pricing for all divisions within the segment (shallow water pipelay,
diving and portable SAT systems). Further, Shelf Contractings revenues increased in 2005 compared
with 2004 directly as a result of the acquisition of the Torch and Acergy vessels in the third and
fourth quarter of 2005, with much of the impact attributable to the fourth quarter.
The increase in our Oil and Gas revenue for the year ended December 31, 2005 was primarily due
to increase in average price realized. These increases were partially offset by lower production
primarily as a result of production shut-ins due to Hurricanes Katrina and Rita in the third and
fourth quarters of 2005.
Gross Profit. Gross profit in 2005 increased 65% as compared to 2004. The Contracting
Services gross profit increase was primarily attributable to improved utilization rates and
contract pricing for all divisions within the segment. Gross profit for the Shelf Contracting
segment also increased as a result of improved utilization rates and contract pricing for all
divisions within the segment. In addition, our Shelf Contracting segment recorded asset
impairments on certain vessels totaling $790,000 in 2005 as compared to $3.9 million in 2004 for
conditions meeting our asset impairment criteria.
Our Oil and Gas gross profit increase was due to the aforementioned higher commodity price
increases, offset by decreased production levels. Further, in 2005, gross profit for the Oil and
Gas segment was also negatively impacted by impairment analysis on certain properties and expensed
well work which resulted in $4.8 million of impairments, inspection and repair costs of
approximately $7.1 million as a result of Hurricanes Katrina and Rita (no insurance recoveries were
recorded as of December 31, 2005), and $5.7 million of expensed seismic data purchased for our
offshore property acquisitions.
Selling & Administrative Expenses. Selling and administrative expenses of $62.8 million for
the year ended December 31, 2005 were $13.9 million higher than the $48.9 million incurred in 2004
due primarily to increased incentive compensation as a result of increased profitability. Selling
and administrative expenses at 8% of revenues for 2005 was slightly lower than the 9% of revenues
in 2004.
30
Equity in Earnings of Investments. Equity in earnings of our 50% investment in Deepwater
Gateway increased to $10.6 million in 2005 compared with $7.9 million in 2004. The increase was
attributable to the demand fees which commenced following the March 2004 mechanical completion of
the Marco Polo tension leg platform, owned by Deepwater Gateway, as well as production tariff
charges which commenced in the third quarter of 2004 as Marco Polo began producing. Further,
equity in earnings from our 40% minority ownership interest in OTSL in 2005 totaled approximately
$2.8 million. We acquired our interest in OTSL in July 2005.
Other (Income) Expense. We reported other expense of $7.6 million for the year ended December
31, 2005 compared to other expense of $5.3 million for the year ended December 31, 2004. Net
interest expense of $7.0 million in 2005 was higher than the $5.6 million incurred in 2004 due
primarily to higher levels of debt associated with our $300 million Convertible Senior Notes which
closed in March 2005. Offsetting the increase in interest expense was $2.0 million of capitalized
interest in 2005, compared with $243,000 in 2004, which related to our investment in Gunnison and
Independence Hub, and interest income of $5.5 million in 2005 compared to $439,000 in 2004.
Income Taxes. Income taxes increased to $75.0 million for the year ended December 31, 2005
compared to $43.0 million in 2004, primarily due to increased profitability. The effective tax
rate of 33% in 2005 was lower than the 34% effective tax rate for 2004 due to our ability to
realize foreign tax credits and oil and gas percentage depletion due to improved profitability both
domestically and in foreign jurisdictions, and implementation of the Internal Revenue Code section
199 manufacturing deduction as it primarily related to oil and gas production. In 2004, we
recognized a benefit for our research and development credits in the first quarter of 2004 as a
result of the conclusion of the Internal Revenue Service (IRS) examination of our income tax
returns for 2001 and 2002, and the tax cost or benefit of U.S. and U.K. branch operations.
Liquidity and Capital Resources
Overview
The following tables present certain information useful in the analysis of our financial
condition and liquidity for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
Net working capital |
|
$ |
310,524 |
|
|
$ |
120,388 |
|
Long-term debt(1) |
|
|
1,454,469 |
|
|
|
440,703 |
|
(1) |
|
Long-term debt does not include current maturities portion of the long-term debt as
amount is included in net working capital. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
Net cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
514,036 |
|
|
$ |
242,432 |
|
|
$ |
226,807 |
|
Investing activities |
|
$ |
(1,379,930 |
) |
|
$ |
(499,925 |
) |
|
$ |
(132,562 |
) |
Financing activities |
|
$ |
978,260 |
|
|
$ |
288,066 |
|
|
$ |
(40,037 |
) |
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 2006
were as follows:
|
|
In July 2006, we borrowed $835 million in a term loan (Term Loan) and entered into a new
$300 million revolving credit facility. The proceeds of the Term Loan were used to fund the
cash portion of the acquisition of Remington. We also issued 13,032,528 shares of our common
stock to the |
31
|
|
Remington shareholders. See Note 10 Long-Term Debt in Item 8. Financial Statements and
Supplementary Data for additional information. |
|
|
|
In December 2006, we completed an IPO of our Shelf Contracting business segment (Cal Dive
International, Inc.), selling 26.5% of that company and receiving pre-tax net proceeds of
$264.4 million. We may sell additional shares of CDI common stock in the future. Proceeds
from the offering were used for general corporate purposes, including the repayment of $71.0
million of our revolving credit facility. See Note 3 Initial Public Offering of Cal Dive,
International, Inc. in Item 8. Financial Statements and Supplementary Data for additional
information. |
|
|
|
In connection with the IPO, CDI Vessel Holdings LLC (CDI Vessel), a subsidiary of CDI,
entered into a secured credit facility for up to $250 million in revolving loans under a
five-year revolving credit facility. During December 2006, CDI Vessel borrowed $201 million
under the revolving credit facility and distributed $200 million of those proceeds to us as a
dividend. CDI expects to use the remaining availability under the revolving credit facility
for working capital and other general corporate purposes (see Note 10 Long-term Debt in
Item 8. Financial Statements and Supplementary Data for a detailed discussion of CDIs credit
facilities). We do not have access to the unused portion of CDIs revolving credit facility. |
|
|
|
In October 2006, we invested $15 million for a 50% interest in Kommandor, a Delaware
limited liability company, to convert a ferry vessel into a dynamically-positioned minimal
floating production system. We have consolidated the results of Kommandor in accordance with
FIN 46. For additional information, see Item 8. Financial Statements and Supplementary Data
Note 9 Consolidated Variable Interest Entities. We have named the vessel Helix Producer
I. |
|
|
|
Also in October 2006, we acquired a 58% interest in Seatrac for total consideration of
approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1
million paid to existing shareholders and $3.4 million for subscription of new Seatrac shares
(see Note 6 Other Acquisitions in Item 8. Financial Statements and Supplementary Data for
a detailed discussion of Seatrac). We changed the name of the entity to Well Ops SEA Pty Ltd. |
|
|
|
In 2006, our Board of Directors also authorized us to discretionarily purchase up to $50
million of our common stock in the open market. In October and November 2006, we purchased
approximately 1.7 million shares under this program for a weighted average price of $29.86 per
share, or $50.0 million. |
Some of the significant financings and corresponding uses during 2005 and 2004 were as
follows:
|
|
In March 2005, we issued $300 million of 3.25% Convertible Senior Notes due 2025
(Convertible Senior Notes). Proceeds from the offering were used for general corporate
purposes including a capital contribution of $72 million (made in March 2005) to Deepwater
Gateway to enable it to repay its term loan and to fund the acquisitions described below.
For additional information on the terms of the Convertible Senior Notes, see Note 10 Long-
term Debt in Item 8. Financial Statements and Supplementary Data. |
|
|
|
In June 2005, we were the high bidder for seven vessels in a bankruptcy auction, including
the Express, and a portable saturation system for approximately $85.9 million, including
certain costs incurred related to the transaction. |
|
|
|
In November 2005, we closed the transaction to purchase the diving assets of Acergy that
operate in the Gulf of Mexico for approximately $46.1 million. In addition, we purchased the
DLB 801 and Kestrel for approximately $78.2 million were closed in the first quarter of 2006
when these assets completed their work campaigns in Trinidadian waters. |
|
|
|
In June 2005, we acquired a mature property package on the Gulf of Mexico shelf from Murphy
Oil Corporation (Murphy). The acquisition cost included both cash ($163.5 million) and the
assumption of the abandonment liability from Murphy of approximately $32.0 million (a non-cash
investing activity). |
|
|
|
In June 2004, the preferred stockholder of our cumulative convertible preferred stock
exercised its right and purchased an additional $30 million of cumulative convertible
preferred stock. As a result, total convertible preferred stock outstanding increased to $55
million. Proceeds from this sale were used for general corporate purposes. For additional
information on our preferred stock, see Note 12 Convertible Preferred Stock in Item 8.
Financial Statements and Supplementary Data. |
32
|
|
In August 2004, we entered into a four-year, $150 million revolving credit facility. We
cancelled this credit facility on June 30, 2006 and replaced it with the aforementioned $300
million revolving credit facility. |
In accordance with the our 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, 2006, 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 however
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.
In 2007, we expect to make $77 million of interest payments, excluding the effect of interest
rate swaps. In addition, we expect to make preferred dividend payments totaling approximately $3.8
million in 2007. As of December 31, 2006, we had $300 million of available borrowing capacity
under our credit facilities, and CDI had $49 million of available borrowing under its revolving
credit facility. See Note 10 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.
Working Capital
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. Working capital 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.
Cash flow from operating activities increased $15.6 million in 2005 as compared to 2004. This
increase was primarily due to higher profitability of $69.9 million as a result of significantly
higher oil and gas prices realized and improved utilization in 2005 as compared to 2004. These
increases were partially offset by negative working capital changes.
33
Investing Activities
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, 2006, 2005 and 2004 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Capital expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting services |
|
$ |
(130,938 |
) |
|
$ |
(90,037 |
) |
|
$ |
(21,016 |
) |
Shelf contracting |
|
|
(38,086 |
) |
|
|
(32,383 |
) |
|
|
(1,792 |
) |
Oil and gas(1) |
|
|
(282,318 |
) |
|
|
(238,698 |
) |
|
|
(27,315 |
) |
Production facilities |
|
|
(17,749 |
) |
|
|
(369 |
) |
|
|
|
|
Acquisition of businesses, net of cash acquired: |
|
|
|
|
|
|
|
|
|
|
|
|
Remington Oil and Gas Corporation(2) |
|
|
(772,244 |
) |
|
|
|
|
|
|
|
|
Acergy US. Inc. (3) |
|
|
(78,174 |
) |
|
|
(66,586 |
) |
|
|
|
|
Fraser Diving International Ltd. (3) |
|
|
(21,954 |
) |
|
|
|
|
|
|
|
|
Seatrac (3) |
|
|
(10,571 |
) |
|
|
|
|
|
|
|
|
Kommandor LLC |
|
|
(5,000 |
) |
|
|
|
|
|
|
|
|
(Purchases) sale of short-term investments |
|
|
(285,395 |
) |
|
|
30,000 |
|
|
|
(30,000 |
) |
Investments in production facilities |
|
|
(27,578 |
) |
|
|
(111,060 |
) |
|
|
(32,206 |
) |
Distributions from equity investments, net(4) |
|
|
|
|
|
|
10,492 |
|
|
|
|
|
Increase in restricted cash |
|
|
(6,666 |
) |
|
|
(4,431 |
) |
|
|
(20,133 |
) |
Affiliate loan to OTSL |
|
|
|
|
|
|
(1,500 |
) |
|
|
|
|
Proceeds from sale of subsidiary stock |
|
|
264,401 |
|
|
|
|
|
|
|
|
|
Proceeds from sale of properties |
|
|
32,342 |
|
|
|
5,617 |
|
|
|
(100 |
) |
Other, net |
|
|
|
|
|
|
(970 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities |
|
$ |
(1,379,930 |
) |
|
$ |
(499,925 |
) |
|
$ |
(132,562 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes approximately $38.3 million of capital expenditures related to
exploratory dry holes in 2006. For additional information, see Item 8. Financial
Statements and Supplementary Data Note 5. |
|
(2) |
|
For additional information related to the Remington acquisition, see Item 8.
Financial Statements and Supplementary Data Note 4. |
|
(3) |
|
For additional information related to the Acergy, Fraser and Seatrac
acquisitions, see Item 8. Financial Statements and Supplementary Data Note 6. |
|
(4) |
|
Distributions from equity investments is net of undistributed equity earnings
from our investments. Gross distributions from our equity investments are detailed
below. |
Short-term Investments
As of December 31, 2006, we held approximately $285.4 million in municipal auction rate
securities. We did not hold these types of securities at December 31, 2005. These instruments are
long-term variable rate bonds tied to short-term interest rates that are reset through a Dutch
Auction process which occurs every 7 to 35 days and have been classified as available-for-sale
securities. Although these instruments do not meet the definition of cash and cash equivalents, we
expect to use these instruments to fund our working capital as needed due to the liquid nature of
these securities.
Restricted Cash
As of December 31, 2006, we had $33.7 million of restricted cash, included in other assets,
net, in the accompanying condensed consolidated balance sheet, all of which related to the escrow
funds for decommissioning liabilities associated with the South Marsh Island 130 (SMI 130)
acquisition in 2002 by our Oil and Gas segment. Under the purchase agreement for the acquisition,
we were obligated to escrow 50% of production up to the first $20 million and 37.5% of production
on the remaining balance up to $33 million in total escrow. We have fully escrowed the requirement
as of December 31, 2006. We may use the restricted cash for decommissioning the related field.
34
Outlook
We anticipate capital expenditures in 2007 will range from $850 million to $1.1 billion. We
may increase or decrease these plans based on various economic factors. We believe internally
generated cash flow, the cash generated from the Cal Dive initial public offering and borrowings
under our existing credit facilities will provide the necessary capital to fund our 2007
initiatives.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of December 31, 2006 and
the scheduled years in which the obligation are contractually due (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than |
|
|
|
|
|
|
|
|
|
|
More Than |
|
|
|
Total (1) |
|
|
1 year |
|
|
1-3 Years |
|
|
3-5 Years |
|
|
5 Years |
|
Convertible Senior Notes(2) |
|
$ |
300,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
300,000 |
|
Term Loan |
|
|
832,900 |
|
|
|
8,400 |
|
|
|
16,800 |
|
|
|
16,800 |
|
|
|
790,900 |
|
MARAD debt |
|
|
131,286 |
|
|
|
3,823 |
|
|
|
8,228 |
|
|
|
9,069 |
|
|
|
110,166 |
|
CDI Revolving Credit Facility |
|
|
201,000 |
|
|
|
|
|
|
|
|
|
|
|
201,000 |
|
|
|
|
|
Loan notes |
|
|
11,146 |
|
|
|
11,146 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital leases |
|
|
4,024 |
|
|
|
2,519 |
|
|
|
1,505 |
|
|
|
|
|
|
|
|
|
Investments in Independence Hub,
LLC(3) |
|
|
4,268 |
|
|
|
4,268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and development costs |
|
|
138,900 |
|
|
|
130,100 |
|
|
|
8,800 |
|
|
|
|
|
|
|
|
|
Property and equipment(4) |
|
|
172,504 |
|
|
|
172,504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases |
|
|
62,958 |
|
|
|
32,205 |
|
|
|
20,652 |
|
|
|
5,421 |
|
|
|
4,680 |
|
Other(6) |
|
|
9,624 |
|
|
|
6,859 |
|
|
|
2,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash obligations |
|
$ |
1,868,610 |
|
|
$ |
371,824 |
|
|
$ |
58,750 |
|
|
$ |
232,290 |
|
|
$ |
1,205,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes unsecured letters of credit outstanding at December 31, 2006 totaling $5.3 million.
These letters of credit primarily guarantee various contract bidding, insurance activities and
shipyard commitments. |
|
(2) |
|
Maturity 2025. Can be converted prior to stated maturity if closing sale price of Helixs
common stock for at least 20 days in the period of 30 consecutive trading days ending on the
last trading day of the preceding fiscal quarter exceeds 120% of the closing price on that
30th trading day (i.e. $38.56 per share) and under certain triggering events as
specified in the indenture governing the Convertible Senior Notes. To the extent we do not
have alternative long-term financing secured to cover the conversion, the Convertible Senior
Notes would be classified as a current liability in the accompanying balance sheet. As of
December 31, 2006, no conversion triggers were met. |
|
(3) |
|
Excludes guaranty of performance related to the construction of the Independence Hub platform
under Independence Hub, LLC (estimated to be immaterial at December 31, 2006). Under the
guaranty agreement with Enterprise, we and Enterprise guarantee performance under the
Independence Hub Agreement between Independence Hub and the producers group of exploration and
production companies up to $426 million, plus applicable attorneys fees and related expenses.
See Item 8. Financial Statements and Supplementary Data Note 8 for additional
information. |
|
(4) |
|
Costs incurred as of December 31, 2006 and additional property and equipment commitments at
December 31, 2006 consisted of the following (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs |
|
|
Costs |
|
|
Total |
|
|
|
Incurred |
|
|
Committed |
|
|
Project Cost |
|
Caesar conversion |
|
$ |
15,014 |
|
|
$ |
52,157 |
|
|
$ |
110,000 |
|
Q4000 upgrade |
|
|
15,300 |
|
|
|
18,966 |
|
|
|
40,000 |
|
Well Enhancer construction |
|
|
19,443 |
|
|
|
87,343 |
|
|
|
160,000 |
|
Helix Producer I conversion |
|
|
16,789 |
|
|
|
14,038 |
|
|
|
160,000 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
66,546 |
|
|
$ |
172,504 |
|
|
$ |
470,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5) |
|
Operating leases included facility leases and vessel charter leases. Vessel charter lease
commitments at December 31, 2006 were approximately $40.2 million. |
|
(6) |
|
Other consisted of scheduled payments pursuant to 3-D seismic license agreements. |
Contingencies
In December 2005 and in May 2006, our Oil and Gas segment received notice from the MMS that
the price threshold was exceeded for 2004 oil and gas production and for 2003 gas production,
respectively, and that royalties are due on such production notwithstanding the provisions of the
DWRRA.
35
As of December 31, 2006, we have approximately $42.6 million accrued for the related royalties
and interest. See Item 8. Financial Statements and Supplementary Data Note 17 for a detailed
discussion of this contingency.
Critical Accounting Estimates and Policies
Our results of operations and financial condition, as reflected in the accompanying financial
statements and related footnotes, are prepared in conformity with accounting principles generally
accepted in the United States. As such, we are required to make certain estimates, judgments and
assumptions that affect the reported amounts of assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the periods presented. We base
our estimates on historical experience, available information and various other assumptions we
believe to be reasonable under the circumstances. These estimates may change as new events occur,
as more experience is acquired, as additional information is obtained and as our operating
environment changes. We believe the most critical accounting policies in this regard are those
described below. While these issues require us to make judgments that are somewhat subjective,
they are generally based on a significant amount of historical data and current market data. For a
detailed discussion on the application of our accounting policies, see Item 8. Financial
Statements and Supplementary Data Notes to Consolidated Financial Statements Note 2
Revenue Recognition
Revenues from Contracting Services and Shelf Contracting are derived from contracts that are
typically of short duration. These contracts contain either lump-sum turnkey provisions or
provisions for specific time, material and equipment charges, which are billed in accordance with
the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts.
Revenues generated from specific time, materials and equipment contracts are generally earned
on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In
connection with these contracts, we may receive revenues for mobilization of equipment and
personnel. In connection with new contracts, revenues related to mobilization are deferred and
recognized over the period in which contracted services are performed using the straight-line
method. Incremental costs incurred directly for mobilization of equipment and personnel to the
contracted site, which typically consist of materials, supplies and transit costs, are also
deferred and recognized over the period in which contracted services are performed using the
straight-line method. Our policy to amortize the revenues and costs related to mobilization on a
straight-line basis over the estimated contract service period is consistent with the general pace
of activity, level of services being provided and dayrates being earned over the service period of
the contract. Mobilization costs to move vessels when a contract does not exist are expensed as
incurred.
Revenue on significant turnkey contracts is recognized on the percentage-of-completion method
based on the ratio of costs incurred to total estimated costs at completion. In determining whether
a contract should be accounted for using the percentage-of-completion method, we consider whether:
|
|
|
the customer provides specifications for the construction of facilities or for
the provision of related services; |
|
|
|
|
we can reasonably estimate our progress towards completion and our costs; |
|
|
|
|
the contract includes provisions as to the enforceable rights regarding the
goods or services to be provided, consideration to be received and the manner
and terms of payment; |
|
|
|
|
the customer can be expected to satisfy its obligations under the contract; and |
|
|
|
|
we can be expected to perform our contractual obligations. |
Under the percentage-of-completion method, we recognize estimated contract revenue based on costs
incurred to date as a percentage of total estimated costs. Changes in the expected cost of
materials and labor, productivity, scheduling and other factors affect the total estimated costs.
Additionally, external factors, including weather or other factors outside of our control, may also
affect the progress and estimated cost of a projects completion and, therefore, the timing of
income and revenue recognition. We
routinely review estimates related to our contracts and reflect revisions to profitability in
earnings on a
36
current basis. If a current estimate of total contract cost indicates an ultimate
loss on a contract, we recognize the projected loss in full when it is first determined. We
recognize additional contract revenue related to claims when the claim is probable and legally
enforceable.
Unbilled revenue represents revenue attributable to work completed prior to period end that
has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2006 and 2005
are expected to be billed and collected within one year.
We record revenues from the sales of crude oil and natural gas when delivery to the customer
has occurred and title has transferred. This occurs when production has been delivered to a
pipeline or a barge lifting has occurred. We may have an interest with other producers in certain
properties. In this case, we use the entitlements method to account for sales of production.
Under the entitlements method, we may receive more or less than our entitled share of production.
If we receive more than our entitled share of production, the imbalance is treated as a liability.
If we receive less than our entitled share, the imbalance is recorded as an asset. As of December
31, 2006, the net imbalance was a $200,000 asset and was included in Other Current Assets ($4.7
million) and Accrued Liabilities ($4.5 million) in the accompanying consolidated balance sheet.
Purchase Price Allocation
In connection with a purchase business combination, the acquiring company must allocate the
cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the
acquisition date. Deferred taxes must be recorded for any differences between the assigned values
and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to
assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular
business combination can vary significantly depending upon the value attributed to assets acquired
and liabilities assumed.
In July 2006, we acquired the assets and assumed the liabilities of Remington in a transaction
accounted for as a business combination. In estimating the fair values of Remingtons assets and
liabilities, we made various assumptions. The most significant assumptions related to the estimated
fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the
fair values of these properties, we prepared estimates of crude oil and natural gas reserves. We
estimated future prices to apply to the estimated reserve quantities acquired, and estimated future
operating and development costs, to arrive at estimates of future net revenues. For estimated
proved reserves, the future net revenues were discounted using a market-based weighted average cost
of capital rate determined appropriate at the time of the merger. The market-based weighted
average cost of capital rate was subjected to additional project-specific risking factors. To
compensate for the inherent risk of estimating and valuing unproved reserves, the estimated
probable and possible reserves were reduced by additional risk-weighting factors.
Estimated deferred taxes were based on available information concerning the tax basis of
Remingtons assets and liabilities and loss carryforwards at the merger date, although such
estimates may change in the future as additional information becomes known.
While the estimates of fair value for the assets acquired and liabilities assumed have no
effect on our cash flows, they can have an effect on the future results of operations. Generally,
higher fair values assigned to crude oil and natural gas properties result in higher future
depreciation, depletion and amortization expense, which results in a decrease in future net
earnings. Also, a higher fair value assigned to crude oil and natural gas properties, based on
higher future estimates of crude oil and natural gas prices, could increase the likelihood of an
impairment in the event of lower commodity prices or higher operating costs than those originally
used to determine fair value. An impairment would have no effect on cash flows but would result in
a decrease in net income for the period in which the impairment is recorded.
Certain data necessary to complete our final purchase price allocation is not yet available,
and includes, but is not limited to, final tax returns that provide the underlying tax bases of
Remingtons assets and liabilities at July 1, 2006, valuation of certain proved and unproved oil
and gas properties and identification and valuation of potential intangible assets. We expect to
complete our valuation of assets
and liabilities (including deferred taxes) for the purpose of allocation of the total purchase
price amount to
37
assets acquired and liabilities assumed during the twelve-month period following
the acquisition date. Any future change in the value of net assets up until the one year period
has expired will be offset by a corresponding increase or decrease in goodwill.
In 2006, we also completed the acquisition of Acergy, FDI and Seatrac. These acquisitions
were accounted for as business combinations as well. We finalized the purchase price allocation
for Acergy in the second quarter of 2006. The allocation of purchase price for FDI was based on
preliminary valuations. Estimates and assumptions are subject to change upon the receipt and
managements review of the final valuations. The primary areas of the purchase price allocation
that are not yet finalized relate to post closing purchase price adjustments. The allocation of
purchase price for Seatrac was based on preliminary valuations. Estimates and assumptions are
subject to change upon the receipt and managements review of the final valuations. The primary
areas of the purchase price allocation that are not yet finalized relate to the identification and
valuation of potential intangible assets and valuation of certain equipment.
Goodwill and Other Intangible Assets
We test for the impairment of goodwill and other indefinite-lived intangible assets on at
least an annual basis. We test for the impairment of other intangible assets when impairment
indicators such as the nature of the assets, the future economic benefit of the assets, any
historical or future profitability measurements and other external market conditions are present.
Our goodwill impairment test involves a comparison of the fair value of each of our reporting units
with its carrying amount. The fair value is determined using discounted cash flows and other
market-related valuation models, such as earnings multiples and comparable asset market values. We
completed our annual goodwill impairment test as of November 1, 2006. Goodwill of $707.6 million
was related to our Oil and Gas segment as of December 31, 2006. The goodwill was attributable to
the Remington acquisition. Goodwill of $88.3 million and $73.9 million was related to our
Contracting Services segment as of December 31, 2006 and 2005, respectively. Goodwill of $26.7
million and $27.8 million was related to our Shelf Contracting segment as of December 31, 2006 and
2005, respectively. None of our goodwill was impaired based on the impairment test performed as of
November 1, 2006. See Item 8. Financial Statements and Supplementary Data Note 2 Summary of
Significant Accounting Policies for goodwill and intangible assets related to the acquisitions.
We will continue to test our goodwill and other indefinite-lived intangible assets annually on a
consistent measurement date unless events occur or circumstances change between annual tests that
would more likely than not reduce the fair value of a reporting unit below its carrying amount.
Income Taxes
Deferred income taxes are based on the difference between financial reporting and tax bases of
assets and liabilities. We utilize the liability method of computing deferred income taxes. The
liability method is based on the amount of current and future taxes payable using tax rates and
laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws
and rates in the countries in which operations are conducted and income is earned. A valuation
allowance for deferred tax assets is recorded when it is more likely than not that some or all of
the benefit from the deferred tax asset will not be realized. We consider the undistributed
earnings of our principal non-U.S. subsidiaries to be permanently reinvested. At December 31,
2006, our principal non-U.S. subsidiaries had accumulated earnings and profits of approximately
$20.3 million. We have not provided deferred U.S. income tax on the accumulated earnings and
profits. See Note 11 Income Taxes in Item 8. Financial Statements and Supplementary Data
included herein for discussion of net operating loss carry forwards and deferred income taxes.
Accounting for Oil and Gas Properties
Acquisitions of producing offshore properties are recorded at the fair value exchanged at
closing together with an estimate of their proportionate share of the decommissioning liability
assumed in the purchase (based upon their working interest ownership percentage). In estimating the
decommissioning
liability assumed in offshore property acquisitions, we perform detailed estimating
procedures, including engineering studies and then reflect the liability at fair value on a
discounted basis as discussed below.
38
We follow the successful efforts method of accounting for our interests in oil and gas
properties. Under the successful efforts method, the costs of successful wells and leases
containing productive reserves are capitalized. Costs incurred to drill and equip development
wells, including unsuccessful development wells, are capitalized. Capitalized costs of producing
oil and gas properties are depleted to operations by the unit-of-production method based on proved
developed oil and gas reserves on a field-by-field basis as determined by our engineers. Costs
incurred relating to unsuccessful exploratory wells are expensed in the period the drilling is
determined to be unsuccessful (see Exploratory Drilling Costs below).
We evaluate the impairment of our proved oil and gas properties on a field-by-field basis at
least annually or whenever events or changes in circumstances indicate an assets carrying amount
may not be recoverable. Unamortized capital costs are reduced to fair value (based upon discounted
cash flows) if the expected undiscounted future cash flows are less than the assets net book
value. Cash flows are determined based upon proved reserves using prices and costs consistent with
those used for internal decision making. Although prices used are likely to approximate market,
they do not necessarily represent current market prices.
We also periodically assess unproved properties for impairment based on exploration and
drilling efforts to date on the individual prospects and lease expiration dates. Managements
assessment of the results of exploration activities, availability of funds for future activities
and the current and projected political climate in areas in which we operate also impact the
amounts and timing of impairment provisions. During 2006, no impairments on unproved oil and gas
properties occurred.
Exploratory Drilling Costs
In accordance with the successful efforts method of accounting, the costs of drilling an
exploratory well are capitalized as uncompleted, or suspended, wells temporarily pending the
determination of whether the well has found proved reserves. If proved reserves are not found,
these capitalized costs are charged to expense. A determination that proved reserves have been
found results in the continued capitalization of the drilling costs of the well and its
reclassification as a well containing proved reserves.
At times, it may be determined that an exploratory well may have found hydrocarbons at the
time drilling is completed, but it may not be possible to classify the reserves at that time. In
this case, we may continue to capitalize the drilling costs as an uncompleted well beyond one year
when the well has found a sufficient quantity of reserves to justify its completion as a producing
well and the company is making sufficient progress assessing the reserves and the economic and
operating viability of the project, or the reserves are deemed to be proved. If reserves are not
ultimately deemed proved or economically viable, the well is considered impaired and its costs, net
of any salvage value, are charged to expense.
Occasionally, we may choose to salvage a portion of an unsuccessful exploratory well in
order to continue exploratory drilling in an effort to reach the target geological
structure/formation. In such cases, we charge only the unusable portion of the well bore to dry
hole expense, and we continue to capitalize the costs associated with the salvageable portion of
the well bore and add the costs to the new exploratory well. In certain situations, the well bore
may be carried for more than one year beyond the date drilling in the original well bore was
suspended. This may be due to the need to obtain, and/or analyze the availability of equipment or
crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed
seismic and geographic data. If, after we analyze the new information and conclude that we will not
reuse the well bore or if the new exploratory well is determined to be unsuccessful after we
complete drilling, we will charge the capitalized costs to dry hole expense.
Estimated Proved Oil and Gas Reserves
The evaluation of our oil and gas reserves is critical to the management of our oil and gas
operations. Decisions such as whether development of a property should proceed and what technical
methods are available for development are based on an evaluation of reserves. These oil and
gas reserve quantities are also used as the basis for calculating the unit-of-production rates for
depreciation,
39
depletion and amortization, evaluating impairment and estimating the life of our
producing oil and gas properties in our decommissioning liabilities. Our proved reserves are
classified as either proved developed or proved undeveloped. Proved developed reserves are those
reserves which can be expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves include reserves expected to be recovered from new
wells from undrilled proven reservoirs or from existing wells where a significant major expenditure
is required for completion and production. We prepare all of our reserve information, and our
independent petroleum engineers audit, the estimates of our oil and gas reserves presented in this
report (U.S. reserves only) based on guidelines promulgated under generally accepted accounting
principles in the United States. See detailed description of our use of the term engineering
audit and our process of preparing reserve estimates in Item 2. Properties Summary of Natural
Gas and Oil Reserve Data. 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 production equipment/facility capacity.
Accounting for Decommissioning Liabilities
Our decommissioning liabilities consist of estimated costs of dismantlement, removal, site
reclamation and similar activities associated with our oil and gas properties. Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS 143)
requires oil and gas companies to reflect decommissioning liabilities on the face of the balance
sheet at fair value on a discounted basis. Prior to the Remington acquisition, we have
historically purchased producing offshore oil and gas properties that are in the later stages of
production. In conjunction with acquiring these properties, we assume an obligation associated
with decommissioning the property in accordance with regulations set by government agencies. The
abandonment liability related to the acquisitions of these properties is determined through a
series of management estimates.
Prior to an acquisition and as part of evaluating the economics of an acquisition, we will
estimate the plug and abandonment liability. Our Oil and Gas operations personnel prepare detailed
cost estimates to plug and abandon wells and remove necessary equipment in accordance with
regulatory guidelines. We currently calculate the discounted value of the abandonment liability
(based on an estimate of the year the abandonment will occur) in accordance with SFAS No. 143 and
capitalize that portion as part of the basis acquired and record the related abandonment liability
at fair value. The recognition of a decommissioning liability requires that management make
numerous estimates, assumptions and judgments regarding such factors as the existence of a legal
obligation for liability; estimated probabilities, amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates. Decommissioning liabilities were
$167.7 million and $121.4 million at December 31, 2006 and 2005, respectively.
On an ongoing basis, our oil and gas operations personnel monitor the status of wells, and as
fields deplete and no longer produce, our personnel will monitor the timing requirements set forth
by the MMS for plugging and abandoning the wells and commence abandonment operations, when
applicable. On an annual basis, management personnel reviews and updates the abandonment estimates
and assumptions for changes, among other things, in market conditions, interest rates and
historical experience.
Derivative Instruments and Hedging Activities
Our price risk management activities involve the use of derivative financial instruments to
hedge the impact of market price risk exposures primarily related to our oil and gas production,
variable
interest rate exposure and foreign currency exposure. To reduce the impact of these risks on
earnings and increase the predictability of our cash flows, from time to time, we have entered into
certain derivative
40
contracts, primarily collars for a portion of our oil and gas production,
interest rate swaps and foreign currency forward contracts. Our oil and gas costless collars,
interest rate swaps and foreign currency forward exchange contracts qualify for hedge accounting
and are reflected in our balance sheet at fair value. Hedge accounting does not apply to our oil
and gas forward sales contracts.
We engage primarily in cash flow hedges. Changes in the derivative fair values that are
designated as cash flow hedges are deferred to the extent that they are effective and are recorded
as a component of accumulated other comprehensive income until the hedged transactions occur and
are recognized in earnings. The ineffective portion of a cash flow hedges change in value is
recognized immediately in earnings.
We formally document all relationships between hedging instruments (oil and gas costless
collars, interest rate swaps and foreign currency forward exchange contracts) and hedged items, as
well as our risk management objectives, strategies for undertaking various hedge transactions and
our methods for assessing and testing correlation and hedge ineffectiveness. All hedging
instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction.
We also assess, both at the inception of the hedge and on an on-going basis, whether the
derivatives that are used in our hedging transactions are highly effective in offsetting changes in
cash flows of the hedged items. Changes in the assumptions used could impact whether the fair
value change in the hedged instrument is charged to earnings or accumulated other comprehensive
income.
The fair value of our oil and gas costless collars reflects our best estimate and is based
upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may
not be available due to location differences or terms that extend beyond the period for which
quotations are available. Where quotes are not available, we utilize other valuation techniques or
models to estimate market values. These modeling techniques require us to make estimates of future
prices, price correlation and market volatility and liquidity. Our actual results may differ from
our estimates, and these differences can be positive or negative.
Property and Equipment
Property and equipment (excluding oil and gas properties and equipment), both owned and under
capital leases, are recorded at cost. Depreciation is provided primarily on the straight-line
method over the estimated useful lives of the assets described in Note 2 Summary of Significant
Accounting Policies in Item 8. Financial Statements and Supplementary Data.
For long-lived assets to be held and used, excluding goodwill, we base our evaluation of
recoverability on impairment indicators such as the nature of the assets, the future economic
benefit of the assets, any historical or future profitability measurements and other external
market conditions or factors that may be present. If such impairment indicators are present or
other factors exist that indicate that the carrying amount of the asset may not be recoverable, we
determine whether an impairment has occurred through the use of an undiscounted cash flows analysis
of the asset at the lowest level for which identifiable cash flows exist. Our marine vessels are
assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. If
an impairment has occurred, we recognize a loss for the difference between the carrying amount and
the fair value of the asset. The fair value of the asset is measured using quoted market prices
or, in the absence of quoted market prices, is based on managements estimate of discounted cash
flows.
Assets are classified as held for sale when we have a plan for disposal of certain assets and
those assets meet the held for sale criteria. Assets held for sale are reviewed for potential loss
on sale when the company commits to a plan to sell and thereafter while the asset is held for sale.
Losses are measured as the difference between the fair value less costs to sell and the assets
carrying value. Estimates of anticipated sales prices are judgmental and subject to revisions in
future periods, although initial estimates are typically based on sales prices for similar assets
and other valuation data.
41
Recertification Costs and Deferred Drydock Charges
Our Contracting Services and Shelf Contracting vessels are required by regulation to be
recertified after certain periods of time. These recertification costs are incurred while the
vessel is in drydock. In addition, routine repairs and maintenance are performed and, at times,
major replacements and improvements are performed. We expense routine repairs and maintenance as
they are incurred. We defer and amortize drydock and related recertification costs over the length
of time for which we expect to receive benefits from the drydock and related recertification, which
is generally 30 months. Vessels are typically available to earn revenue for the 30-month period
between drydock and related recertification processes. A drydock and related recertification
process typically lasts one to two months, a period during which the vessel is not available to
earn revenue. Major replacements and improvements, which extend the vessels economic useful life
or functional operating capability, are capitalized and depreciated over the vessels remaining
economic useful life. Inherent in this process are estimates we make regarding the specific cost
incurred and the period that the incurred cost will benefit.
As of December 31, 2006 and 2005, capitalized deferred drydock charges (described in Note 7
Detail of Certain Accounts in Item 8. Financial Statements and Supplementary Data) totaled $26.4
million and $18.3 million, respectively. During the years ended December 31, 2006, 2005 and 2004,
drydock amortization expense was $12 million, $8.9 million and $4.9 million, respectively. We
expect drydock amortization expense to increase in future periods since there was only limited
amortization expense associated with the vessels we acquired in the Torch and Acergy acquisitions
during the year ended December 31, 2006.
Equity Investments
We periodically review our investments in Deepwater Gateway, Independence Hub and OTSL for
impairment. Under the equity method of accounting, an impairment loss would be recorded whenever a
decline in value of an equity investment below its carrying amount is determined to be other than
temporary. In judging other than temporary, we would consider the length of time and extent to
which the fair value of the investment has been less than the carrying amount of the equity
investment, the near-term and longer-term operating and financial prospects of the equity company
and our longer-term intent of retaining the investment in the entity. OTSL generated a net
operating loss during 2006 which is an impairment indicator. As a result, we evaluated this
investment to determine whether a permanent loss in value had occurred. We believe the current
trend is temporary and have determined that the fair value of this investment, based on an estimate
of its discounted cash flows, exceeds its carrying amount, and as a result there is no impairment
at December 31, 2006.
Workers Compensation Claims
Our onshore employees are covered by Workers Compensation. Offshore employees, including
divers, tenders and marine crews, are covered by our Maritime Employers Liability insurance policy
which covers Jones Act exposures. We incur workers compensation claims in the normal course of
business, which management believes are substantially covered by insurance. Our insurers and legal
counsel and we analyze each claim for potential exposure and estimate the ultimate liability of
each claim.
Recently Issued Accounting Principles
In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of FASB Statement No. 109 (FIN 48), which clarifies the accounting for
uncertainty in income taxes recognized in accordance with FASB Statement No. 109, Accounting for
Income Taxes (SFAS No. 109). FIN 48 clarifies the application of SFAS No. 109 by defining
criteria that an individual tax position must meet for any part of the benefit of that position to
be recognized in the financial statements. Additionally, FIN 48 provides guidance on the
measurement, derecognition, classification and disclosure of tax positions, along with accounting
for the related interest and penalties. The provisions of FIN 48 are effective for fiscal years
beginning after December 15, 2006, with the cumulative effect of the change in accounting principle
recorded as an adjustment to opening retained earnings. We adopted the provisions of FIN 48. The
impact of the adoption of FIN 48 was immaterial on our financial position, results of operations
and cash flows.
42
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (SFAS No.
157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in
accordance with generally accepted accounting principles and expands disclosures about fair value
measurements. The provisions of SFAS No. 157 are effective for fiscal years beginning after
November 15, 2007. We are currently evaluating the impact, if any, of this statement.
43
Item 8. Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page |
Managements Report on Internal Control Over Financial Reporting |
|
|
45 |
|
Report of Independent Registered Public Accounting Firm |
|
|
46 |
|
Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting |
|
|
47 |
|
Consolidated Balance Sheets as of December 31, 2006 and 2005 |
|
|
48 |
|
Consolidated Statements of Operations for the Years Ended
December 31, 2006, 2005 and 2004 |
|
|
49 |
|
Consolidated Statements of Shareholders Equity for the Years Ended
December 31, 2006, 2005 and 2004 |
|
|
50 |
|
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2006, 2005 and 2004 |
|
|
51 |
|
Notes to the Consolidated Financial Statements |
|
|
52 |
|
44
Managements Report on Internal Control Over Financial Reporting
Management of Helix Energy Solutions Group, Inc., together with its consolidated subsidiaries
(the Company), is responsible for establishing and maintaining adequate internal control over
financial reporting. The Companys internal control over financial reporting is a process designed
under the supervision of the Companys principal executive and principal financial officers to
provide reasonable assurance regarding the reliability of financial reporting and the preparation
of the Companys financial statements for external reporting purposes in accordance with U.S.
generally accepted accounting principles.
As of the end of the Companys 2006 fiscal year, management conducted an assessment of the
effectiveness of the Companys internal control over financial reporting using the criteria set
forth in the framework established in Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment,
management has determined that the Companys internal control over financial reporting as of
December 31, 2006 was effective.
Our internal control over financial reporting includes policies and procedures that pertain to
the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions
and dispositions of assets of the Company; provide reasonable assurances that transactions are
recorded as necessary to permit preparation of financial statements in accordance with U.S.
generally accepted accounting principles, and that receipts and expenditures are being made only in
accordance with authorizations of management and the directors of the Company; and provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or
disposition of the Companys assets that could have a material effect on our financial statements.
Managements assessment of the effectiveness of the Companys internal control over financial
reporting as of December 31, 2006 has been audited by Ernst & Young LLP, an independent registered
public accounting firm, as stated in their report appearing on page 47, which expresses an
unqualified opinion on managements assessment and on the effectiveness of Companys internal
control over financial reporting as of December 31, 2006.
45
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Helix Energy Solutions Group, Inc.
We have audited the accompanying consolidated balance sheets of Helix Energy Solutions Group,
Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of
operations, shareholders equity and cash flows for each of the three years in the period ended
December 31, 2006. These financial statements are the responsibility of the Companys management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of Helix Energy Solutions Group, Inc. and
subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and
their cash flows for each of the three years in the period ended December 31, 2006, in conformity
with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Helix Energy Solutions Group, Inc.s internal
control over financial reporting as of December 31, 2006, based on criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 28, 2007 expressed an unqualified opinion thereon.
As discussed in Note 13 to the consolidated financial statements, effective January 1, 2006,
the Company adopted Statement of Financial Accounting Standards No. 123 (Revised 2004),
Share-Based Payment.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2007
46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Helix Energy Solutions Group, Inc.
We have audited managements assessment, included in the accompanying Managements Report on
Internal Control Over Financial Reporting, that Helix Energy Solutions Group, Inc. maintained
effective internal control over financial reporting as of December 31, 2006, based on criteria
established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Helix Energy Solutions Group, Inc.s
management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting. Our
responsibility is to express an opinion on managements assessment and an opinion on the
effectiveness of the companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion.
A companys internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting
principles. A companys internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the companys assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that Helix Energy Solutions Group, Inc. maintained
effective internal control over financial reporting as of December 31, 2006, is fairly stated, in
all material respects, based on the COSO criteria. Also, in our opinion, Helix Energy Solutions
Group, Inc. maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Helix Energy Solutions Group,
Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of
operations, shareholders equity and cash flows for each of the three years in the period ended
December 31, 2006 and our report dated February 28, 2007 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2007
47
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
206,264 |
|
|
$ |
91,080 |
|
Short-term investments |
|
|
285,395 |
|
|
|
|
|
Accounts receivable |
|
|
|
|
|
|
|
|
Trade, net of allowance for uncollectible accounts
of $982 and $585 |
|
|
287,875 |
|
|
|
197,046 |
|
Unbilled revenue |
|
|
82,834 |
|
|
|
31,012 |
|
Other current assets |
|
|
61,532 |
|
|
|
52,915 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
923,900 |
|
|
|
372,053 |
|
|
|
|
|
|
|
|
Property and equipment |
|
|
2,721,362 |
|
|
|
1,259,014 |
|
Less Accumulated depreciation |
|
|
(508,904 |
) |
|
|
(342,652 |
) |
|
|
|
|
|
|
|
|
|
|
2,212,458 |
|
|
|
916,362 |
|
Other assets: |
|
|
|
|
|
|
|
|
Equity investments |
|
|
213,362 |
|
|
|
179,844 |
|
Goodwill, net |
|
|
822,556 |
|
|
|
101,731 |
|
Other assets, net |
|
|
117,911 |
|
|
|
90,874 |
|
|
|
|
|
|
|
|
|
|
$ |
4,290,187 |
|
|
$ |
1,660,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
240,067 |
|
|
$ |
99,445 |
|
Accrued liabilities |
|
|
199,650 |
|
|
|
138,464 |
|
Income taxes payable |
|
|
147,772 |
|
|
|
7,288 |
|
Current maturities of long-term debt |
|
|
25,887 |
|
|
|
6,468 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
613,376 |
|
|
|
251,665 |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
1,454,469 |
|
|
|
440,703 |
|
Deferred income taxes |
|
|
436,544 |
|
|
|
167,295 |
|
Decommissioning liabilities |
|
|
138,905 |
|
|
|
106,317 |
|
Other long-term liabilities |
|
|
6,143 |
|
|
|
10,584 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
2,649,437 |
|
|
|
976,564 |
|
|
|
|
|
|
|
|
|
|
Minority interests |
|
|
59,802 |
|
|
|
|
|
Convertible preferred stock |
|
|
55,000 |
|
|
|
55,000 |
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
Shareholders equity: |
|
|
|
|
|
|
|
|
Common stock, no par, 240,000 shares authorized,
90,628 and 77,694 shares issued |
|
|
745,928 |
|
|
|
229,796 |
|
Retained earnings |
|
|
752,784 |
|
|
|
408,748 |
|
Unearned compensation |
|
|
|
|
|
|
(7,515 |
) |
Accumulated other comprehensive income (loss) |
|
|
27,236 |
|
|
|
(1,729 |
) |
|
|
|
|
|
|
|
Total shareholders equity |
|
|
1,525,948 |
|
|
|
629,300 |
|
|
|
|
|
|
|
|
|
|
$ |
4,290,187 |
|
|
$ |
1,660,864 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
48
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Net revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting services |
|
$ |
937,317 |
|
|
$ |
523,659 |
|
|
$ |
300,082 |
|
Oil and gas |
|
|
429,607 |
|
|
|
275,813 |
|
|
|
243,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,366,924 |
|
|
|
799,472 |
|
|
|
543,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting services |
|
|
584,295 |
|
|
|
383,063 |
|
|
|
263,597 |
|
Oil and gas |
|
|
267,221 |
|
|
|
133,337 |
|
|
|
107,883 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
851,516 |
|
|
|
516,400 |
|
|
|
371,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit |
|
|
515,408 |
|
|
|
283,072 |
|
|
|
171,912 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of assets |
|
|
2,817 |
|
|
|
1,405 |
|
|
|
|
|
Selling and administrative expenses |
|
|
119,580 |
|
|
|
62,790 |
|
|
|
48,881 |
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
398,645 |
|
|
|
221,687 |
|
|
|
123,031 |
|
Equity in earnings of investments |
|
|
18,130 |
|
|
|
13,459 |
|
|
|
7,927 |
|
Gain on subsidiary equity transaction |
|
|
223,134 |
|
|
|
|
|
|
|
|
|
Net interest expense and other |
|
|
34,634 |
|
|
|
7,559 |
|
|
|
5,265 |
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
605,275 |
|
|
|
227,587 |
|
|
|
125,693 |
|
Provision for income taxes |
|
|
257,156 |
|
|
|
75,019 |
|
|
|
43,034 |
|
Minority interest |
|
|
725 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
347,394 |
|
|
|
152,568 |
|
|
|
82,659 |
|
Preferred stock dividends |
|
|
3,358 |
|
|
|
2,454 |
|
|
|
2,743 |
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common shareholders |
|
$ |
344,036 |
|
|
$ |
150,114 |
|
|
$ |
79,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
4.07 |
|
|
$ |
1.94 |
|
|
$ |
1.05 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
3.87 |
|
|
$ |
1.86 |
|
|
$ |
1.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
84,613 |
|
|
|
77,444 |
|
|
|
76,409 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
89,874 |
|
|
|
82,205 |
|
|
|
79,062 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
49
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Total |
|
|
|
Common Stock |
|
|
Retained |
|
|
Unearned |
|
|
Comprehensive |
|
|
Shareholders |
|
|
|
Shares |
|
|
Amount |
|
|
Earnings |
|
|
Compensation |
|
|
Income (Loss) |
|
|
Equity |
|
Balance, December 31, 2003 |
|
|
75,716 |
|
|
$ |
196,258 |
|
|
$ |
178,718 |
|
|
$ |
|
|
|
$ |
6,165 |
|
|
$ |
381,141 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
82,659 |
|
|
|
|
|
|
|
|
|
|
|
82,659 |
|
Foreign currency translations
Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,780 |
|
|
|
10,780 |
|
Unrealized gain on hedges, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
846 |
|
|
|
846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
(1,620 |
) |
|
|
|
|
|
|
|
|
|
|
(1,620 |
) |
Accretion of preferred stock costs |
|
|
|
|
|
|
|
|
|
|
(1,123 |
) |
|
|
|
|
|
|
|
|
|
|
(1,123 |
) |
Activity in company stock plans, net |
|
|
1,120 |
|
|
|
10,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,481 |
|
Tax benefit from exercise of stock
options |
|
|
|
|
|
|
2,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004 |
|
|
76,836 |
|
|
|
208,867 |
|
|
|
258,634 |
|
|
|
|
|
|
|
17,791 |
|
|
|
485,292 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
152,568 |
|
|
|
|
|
|
|
|
|
|
|
152,568 |
|
Foreign currency translations
adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,393 |
) |
|
|
(11,393 |
) |
Unrealized loss on hedges, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,127 |
) |
|
|
(8,127 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
(2,454 |
) |
|
|
|
|
|
|
|
|
|
|
(2,454 |
) |
Activity in company stock plans, net |
|
|
858 |
|
|
|
16,527 |
|
|
|
|
|
|
|
(7,515 |
) |
|
|
|
|
|
|
9,012 |
|
Tax benefit from exercise of stock
options |
|
|
|
|
|
|
4,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005 |
|
|
77,694 |
|
|
|
229,796 |
|
|
|
408,748 |
|
|
|
(7,515 |
) |
|
|
(1,729 |
) |
|
|
629,300 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
347,394 |
|
|
|
|
|
|
|
|
|
|
|
347,394 |
|
Foreign currency translations
adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,601 |
|
|
|
17,601 |
|
Unrealized gain on hedges, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,364 |
|
|
|
11,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
376,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
(3,358 |
) |
|
|
|
|
|
|
|
|
|
|
(3,358 |
) |
Stock compensation expense |
|
|
|
|
|
|
9,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,364 |
|
Adoption of SFAS 123R |
|
|
|
|
|
|
(7,515 |
) |
|
|
|
|
|
|
7,515 |
|
|
|
|
|
|
|
|
|
Stock issuance |
|
|
13,033 |
|
|
|
553,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
553,570 |
|
Stock repurchase |
|
|
(1,682 |
) |
|
|
(50,266 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(50,266 |
) |
Activity in company stock plans, net |
|
|
1,583 |
|
|
|
8,319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,319 |
|
Tax benefit from exercise of stock
options |
|
|
|
|
|
|
2,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006 |
|
|
90,628 |
|
|
$ |
745,928 |
|
|
$ |
752,784 |
|
|
$ |
|
|
|
$ |
27,236 |
|
|
$ |
1,525,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
50
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
347,394 |
|
|
$ |
152,568 |
|
|
$ |
82,659 |
|
Adjustments to reconcile net income to net cash provided
by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
193,647 |
|
|
|
110,683 |
|
|
|
104,405 |
|
Asset impairment charge |
|
|
|
|
|
|
790 |
|
|
|
3,900 |
|
Dry hole expense |
|
|
38,335 |
|
|
|
|
|
|
|
|
|
Equity in earnings of investments, net of distributions |
|
|
(1,879 |
) |
|
|
(2,851 |
) |
|
|
(469 |
) |
Amortization of deferred financing costs |
|
|
2,277 |
|
|
|
1,126 |
|
|
|
1,344 |
|
Stock compensation expense |
|
|
9,364 |
|
|
|
1,406 |
|
|
|
|
|
Deferred income taxes |
|
|
57,235 |
|
|
|
42,728 |
|
|
|
42,046 |
|
Excess tax benefit from stock-based compensation |
|
|
(2,660 |
) |
|
|
4,402 |
|
|
|
2,128 |
|
Gain on subsidiary equity transaction |
|
|
(223,134 |
) |
|
|
|
|
|
|
|
|
(Gain) loss on sale of assets |
|
|
(2,817 |
) |
|
|
(1,405 |
) |
|
|
100 |
|
Minority interest |
|
|
725 |
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net |
|
|
(67,211 |
) |
|
|
(107,163 |
) |
|
|
(17,397 |
) |
Other current assets |
|
|
9,969 |
|
|
|
(6,997 |
) |
|
|
(23,294 |
) |
Income tax payable |
|
|
142,949 |
|
|
|
5,384 |
|
|
|
771 |
|
Accounts payable and accrued liabilities |
|
|
39,551 |
|
|
|
59,241 |
|
|
|
42,521 |
|
Other noncurrent, net |
|
|
(29,709 |
) |
|
|
(17,480 |
) |
|
|
(11,907 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
514,036 |
|
|
|
242,432 |
|
|
|
226,807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(469,091 |
) |
|
|
(361,487 |
) |
|
|
(50,123 |
) |
Acquisition of businesses, net of cash acquired |
|
|
(887,943 |
) |
|
|
(66,586 |
) |
|
|
|
|
(Purchases) sale of short-term investments |
|
|
(285,395 |
) |
|
|
30,000 |
|
|
|
(30,000 |
) |
Investments in equity investments |
|
|
(27,578 |
) |
|
|
(111,060 |
) |
|
|
(32,206 |
) |
Distributions from equity investments, net |
|
|
|
|
|
|
10,492 |
|
|
|
|
|
Increase in restricted cash |
|
|
(6,666 |
) |
|
|
(4,431 |
) |
|
|
(20,133 |
) |
Proceeds from sale of subsidiary stock |
|
|
264,401 |
|
|
|
|
|
|
|
|
|
Proceeds from (payments on) sales of property |
|
|
32,342 |
|
|
|
5,617 |
|
|
|
(100 |
) |
Other, net |
|
|
|
|
|
|
(2,470 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(1,379,930 |
) |
|
|
(499,925 |
) |
|
|
(132,562 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit facilities |
|
|
1,036,000 |
|
|
|
|
|
|
|
|
|
Repayment of credit facilities |
|
|
(2,100 |
) |
|
|
|
|
|
|
|
|
Borrowings on Convertible Senior Notes |
|
|
|
|
|
|
300,000 |
|
|
|
|
|
Sale of convertible preferred stock, net of transaction costs |
|
|
|
|
|
|
|
|
|
|
29,339 |
|
Borrowings under MARAD loan facility |
|
|
|
|
|
|
2,836 |
|
|
|
|
|
Repayment of MARAD borrowings |
|
|
(3,641 |
) |
|
|
(4,321 |
) |
|
|
(2,946 |
) |
Borrowing under loan notes |
|
|
5,000 |
|
|
|
|
|
|
|
|
|
Repayment on line of credit |
|
|
|
|
|
|
|
|
|
|
(30,189 |
) |
Deferred financing costs |
|
|
(11,839 |
) |
|
|
(11,678 |
) |
|
|
(4,550 |
) |
Repayments of term loan borrowings |
|
|
|
|
|
|
|
|
|
|
(35,000 |
) |
Capital lease payments |
|
|
(2,827 |
) |
|
|
(2,859 |
) |
|
|
(3,647 |
) |
Preferred stock dividends paid |
|
|
(3,613 |
) |
|
|
(2,200 |
) |
|
|
(1,620 |
) |
Redemption of stock in subsidiary |
|
|
|
|
|
|
(2,438 |
) |
|
|
(2,462 |
) |
Repurchase of common stock |
|
|
(50,266 |
) |
|
|
|
|
|
|
|
|
Excess tax benefit from stock-based compensation |
|
|
2,660 |
|
|
|
|
|
|
|
|
|
Exercise of stock options, net |
|
|
8,886 |
|
|
|
8,726 |
|
|
|
11,038 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
978,260 |
|
|
|
288,066 |
|
|
|
(40,037 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
2,818 |
|
|
|
(635 |
) |
|
|
556 |
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
115,184 |
|
|
|
29,938 |
|
|
|
54,764 |
|
Cash and cash equivalents: |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
91,080 |
|
|
|
61,142 |
|
|
|
6,378 |
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
$ |
206,264 |
|
|
$ |
91,080 |
|
|
$ |
61,142 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
51
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 Organization
Effective March 6, 2006, Cal Dive International, Inc. changed its name to Helix Energy
Solutions Group, Inc. (Helix or the Company). Unless the context indicates otherwise, the
terms we, us and our in this report refer collectively to Helix and its subsidiaries. We are
an international offshore energy company that provides development solutions and other key services
(contracting services operations) to the open market as well as to our own reservoirs (oil and gas
operations). Our oil and gas business is a prospect generating, exploration, development and
production company.
Contracting Services Operations
We seek to provide services and methodologies which we believe are critical to finding and
developing offshore reservoirs and maximizing the economics from marginal fields. Those life of
field services are organized in five disciplines: reservoir and well tech services, drilling,
production facilities, construction and well operations. We have disaggregated our contracting
services operations into three reportable segments in accordance with SFAS 131: Contracting
Services (which currently includes deepwater construction, well ops and reservoir and well tech
services); Shelf Contracting and Production Facilities. Within our contracting services
operations, we operate primarily in the Gulf of Mexico, the North Sea and Asia/Pacific regions,
with services that cover the lifecycle of an offshore oil or gas field. The assets of our Shelf
Contracting segment, including the 40% interest in Offshore Technology Solutions Limited (OTSL),
are the assets of Cal Dive International, Inc. (Cal Dive or CDI). In December 2006, Cal Dive
completed an initial public offering of 22,173,000 shares of its stock. As a result of Cal Dives
initial public offering, together with shares issued to CDI employees immediately after the
offering, our ownership in CDI was 73.0% as of December 31, 2006.
Oil and Gas Operations
In 1992 we began our oil and gas operations to provide a more efficient solution to offshore
abandonment, to expand our off-season asset utilization and to achieve better returns than are
likely through pure service contracting. Over the last 15 years we have evolved this business
model to include not only mature oil and gas properties but also proved reserves yet to be
developed, and most recently with the acquisition of Remington, an exploration, development and
production company. This has led to the assembly of services that allows us to create value at key
points in the life of a reservoir from exploration through development, life of field management
and operating through abandonment.
Note 2 Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of majority-owned subsidiaries and
variable interest entities in which we are the primary beneficiary. The equity method is used to
account for investments in affiliates in which we do not have majority ownership, but have the
ability to exert significant influence. We account for our investments in Deepwater Gateway,
Independence Hub and OTSL under the equity method of accounting. Minority interests represent
minority shareholders proportionate share of the equity in CDI, Seatrac and Kommandor. All
material intercompany accounts and transactions have been eliminated.
Certain reclassifications were made to previously reported amounts in the consolidated
financial statements and notes thereto to make them consistent with the current presentation
format. Reclassifications of prior year information to current year presentation related primarily
to the following:
|
|
|
reporting dry hole cost as a component of our exploration costs instead of as a
component of depreciation, depletion and amortization costs on the statement of cash
flows due to the significance of our oil and gas exploration activities as a result of
our recent acquisition of Remington (see Note 5 Oil and Gas Properties); |
|
|
|
|
reporting the purchase and sale of municipal auction rate securities from net cash
provided by operating activities to net cash provided by (used in) investing
activities for 2006, 2005
and 2004; and |
52
|
|
|
reporting treasury stock outstanding as a component of common stock as of December
31, 2006, 2005 and 2004 as treasury stock is not legally recognized in Minnesota, our
state of incorporation. |
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents are highly liquid financial instruments with original maturities of
three months or less. They are carried at cost plus accrued interest, which approximates fair
value.
Statement of Cash Flow Information
As of December 31, 2006 and 2005, we had $33.7 million and $27.0 million, respectively, of
restricted cash (see Note 7 Detail of Certain Accounts) all of which was related to the
escrow funds for decommissioning liabilities associated with the SMI 130 acquisition in 2002 by our
Oil and Gas segment. Under the purchase agreement for those acquisitions, we were obligated to
escrow 50% of production up to the first $20 million of escrow and 37.5% of production on the
remaining balance up to $33 million in total escrow. We had fully escrowed the requirement as of
December 31, 2006. We may use the restricted cash for decommissioning the related field.
The following table provides supplemental cash flow information for the periods stated (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
Interest paid (net of capitalized interest) |
|
$ |
26,105 |
|
|
$ |
9,990 |
|
|
$ |
3,224 |
|
Income taxes paid |
|
$ |
56,972 |
|
|
$ |
22,495 |
|
|
$ |
252 |
|
Non-cash investing activities for the years ended December 31, 2006, 2005 and 2004
included $39.0 million, $28.5 million and $8.9 million, respectively, related to accruals of
capital expenditures. The accruals have been reflected in the consolidated balance sheet as an
increase in property and equipment and accounts payable.
Short-term Investments
Short-term investments are available-for-sale instruments that we expect to realize in cash
within one year. These investments are stated at cost, which approximates market value. Any
unrealized holding gains or losses are reported in comprehensive income until realized. All of our
short-term investments at December 31, 2006 were municipal auction rate securities. We did not
hold these types of securities at December 31, 2005. These instruments are long-term variable rate
bonds tied to short-term interest rates that are reset through a Dutch Auction process which
occurs every 7 to 35 days and have been classified as available-for-sale securities. The stated
maturities of these securities range from November 2015 to November 2045. Although these
instruments do not meet the definition of cash and cash equivalents, we expect to use these
instruments to fund our working capital as needed due to the liquid nature of these securities. As
a result, they are classified as short-term investments.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable are stated at the historical carrying amount net of write-offs and
allowance for uncollectible accounts. We establish an allowance for uncollectible accounts
receivable based on historical experience and any specific customer collection issues that we have
identified. Uncollectible
53
accounts receivable are written off when a settlement is reached for an amount that is less
than the outstanding historical balance or when we have determined that the balance will not be
collected.
Property and Equipment
Overview. Property and equipment, both owned and under capital leases, are recorded at cost.
The following is a summary of the components of property and equipment (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
Useful Life |
|
2006 |
|
|
2005 |
|
Vessels |
|
10 to 30 years |
|
$ |
883,635 |
|
|
$ |
609,558 |
|
Offshore oil and gas leases and related equipment |
|
Units-of-Production |
|
|
1,746,896 |
|
|
|
601,866 |
|
Machinery, equipment buildings and
leasehold improvements |
|
5 to 30 years |
|
|
90,831 |
|
|
|
47,590 |
|
|
|
|
|
|
|
|
|
|
Total property and equipment |
|
|
|
$ |
2,721,362 |
|
|
$ |
1,259,014 |
|
|
|
|
|
|
|
|
|
|
The cost of repairs and maintenance is charged to operations as incurred, while the cost
of improvements is capitalized. Total repair and maintenance charges were $51.0 million, $24.0
million and $17.0 million for the years ended December 31, 2006, 2005 and 2004, respectively.
For long-lived assets to be held and used, excluding goodwill, we base our evaluation of
recoverability on impairment indicators such as the nature of the assets, the future economic
benefit of the assets, any historical or future profitability measurements and other external
market conditions or factors that may be present. If such impairment indicators are present or
other factors exist that indicate the carrying amount of the asset may not be recoverable, we
determine whether an impairment has occurred through the use of an undiscounted cash flows analysis
of the asset at the lowest level for which identifiable cash flows exist. Our marine vessels are
assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. If
an impairment has occurred, we recognize a loss for the difference between the carrying amount and
the fair value of the asset. Impairment expenses are included as a component of cost of sales. The
fair value of the asset is measured using quoted market prices or, in the absence of quoted market
prices, is based on an estimate of discounted cash flows. During 2005 and 2004, we recorded
impairment charges of $790,000 and $3.9 million, respectively, on certain vessels that met the
impairment criteria. Such charges are included in cost of sales in the accompanying Consolidated
Statements of Operations. These assets were subsequently sold in 2005 and 2006, for an aggregate
gain on the disposals of approximately $322,000. There were no such impairments during 2006.
Assets are classified as held for sale when we have a plan for disposal of certain assets and
those assets meet the held for sale criteria. At December 31, 2006 and 2005, we had classified
certain assets intended to be disposed of within a 12-month period as assets held for sale totaling
approximately $700,000 and $7.9 million, respectively. Assets classified as held for sale are
included in other current assets (see Note 7 Detail of Certain Accounts). Remaining assets
held for sale were disposed of in January 2007.
In March 2005, we completed the sale of certain Contracting Services property and equipment
for $4.5 million that was previously included in assets held for sale. Proceeds from the sale
consisted of $100,000 cash and a $4.4 million promissory note bearing interest at 6% per annum due
in semi-annual installments beginning September 30, 2005 through March 31, 2010. In addition to
the asset sale, we entered into a five-year services agreement with the purchaser whereby we have
committed to provide the purchaser with a specified amount of services for its Gulf of Mexico fleet
on an annual basis ($8 million per year). The measurement period related to the services agreement
began with the twelve months ending June 30, 2006 and continues every six months until the contract
ends on March 31, 2010. Further, the promissory note stipulates that should we not meet our annual
services commitment, the purchaser can defer its semi-annual principal and interest payment for six
months. We determined that the estimated gain on the sale of approximately $2.5 million should be
deferred and recognized as the principal and interest payments are received from the purchaser over
the term of the promissory note. As of December 31, 2006 and 2005, the balance of the outstanding
receivable was $3.6 million and $4.0 million, respectively, and for the years ended December 31,
2006 and 2005, we recognized $216,000 and
54
$210,000, respectively, of partial gain on this sale.
Depreciation and Depletion. Depletion for our oil and gas properties is calculated on a
unit-of-production basis. The calculation is based on the estimated remaining oil and gas
reserves. Depreciation for all other property and equipment is provided on a straight-line basis
over the estimated useful lives of the assets.
Oil and Gas Properties. The majority of our interests in oil and gas properties are located
offshore in United States waters. We follow the successful efforts method of accounting for our
interests in oil and gas properties. Under this method, the costs of successful wells and leases
containing productive reserves are capitalized. Costs incurred to drill and equip development
wells, including unsuccessful development wells, are capitalized. Costs incurred relating to
unsuccessful exploratory wells are expensed in the period when the drilling is determined to be
unsuccessful. See Exploratory Costs below. Properties are periodically assessed for
impairment in value, with any impairment charged to expense.
Unproved Properties. We also periodically assess unproved properties for impairment based on
exploration and drilling efforts to date on the individual prospects and lease expiration dates.
Managements assessment of the results of exploration activities, availability of funds for future
activities and the current and projected political climate in areas in which we operate also impact
the amounts and timing of impairment provisions. During 2006, no impairment of unproved oil and
gas properties was recorded.
Exploratory Costs. The costs of drilling an exploratory well are capitalized as uncompleted,
or suspended, wells temporarily pending the determination of whether the well has found proved
reserves. If proved reserves are not found, these capitalized costs are charged to expense. A
determination that proved reserves have been found results in the continued capitalization of the
drilling costs of the well and its reclassification as a well containing proved reserves. At
times, it may be determined that an exploratory well may have found hydrocarbons at the time
drilling is completed, but it may not be possible to classify the reserves at that time. In this
case, we may continue to capitalize the drilling costs as an uncompleted, or suspended, well
beyond one year if we can justify its completion as a producing well and we are making sufficient
progress assessing the reserves and the economic and operating viability of the project. If
reserves are not ultimately deemed proved or economically viable, the well is considered impaired
and its costs, net of any salvage value, are charged to expense.
Occasionally, we may choose to salvage a portion of an unsuccessful exploratory well in
order to continue exploratory drilling in an effort to reach the target geological
structure/formation. In such cases, we charge only the unusable portion of the well bore to dry
hole expense, and we continue to capitalize the costs associated with the salvageable portion of
the well bore and add the costs to the new exploratory well. In certain situations, the well bore
may be carried for more than one year beyond the date drilling in the original well bore was
suspended. This may be due to the need to obtain, and/or analyze the availability of, equipment or
crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed
seismic and geographic data. If, after we analyze the new information and conclude that we will not
reuse the well bore or if the new exploratory well is determined to be unsuccessful after we
complete drilling, we will charge the capitalized costs to dry hole expense. See Note 5
Oil and Gas Properties for detailed discussion of our exploratory activities.
Property Acquisition Costs. Acquisitions of producing properties are recorded at the value
exchanged at closing together with an estimate of our proportionate share of the discounted
decommissioning liability assumed in the purchase based upon the working interest ownership
percentage.
Properties Acquired from Business Combinations. Properties acquired through business
combinations are recorded at their fair value. In determining the fair value of the proved and
unproved properties, we prepare estimates of oil and gas reserves. We estimate future prices to
apply to the estimated reserve quantities acquired and the estimated future operating and
development costs to arrive at our estimates of future net revenues. For the fair value assigned
to proved reserves, the future net revenues are discounted using a market-based weighted average
cost of capital rate determined appropriate at the time of the acquisition. To compensate for
inherent risks of estimating and valuing
55
unproved reserves, probable and possible reserves are
reduced by additional risk weighting factors. See Note 4 for a detailed discussion of our
acquisition of Remington.
Capitalized Interest. Interest from external borrowings is capitalized on major projects.
Capitalized interest is added to the cost of the underlying asset and is amortized over the useful
lives of the assets in the same manner as the underlying assets.
Equity Investments
We periodically review our investments in Deepwater Gateway, Independence Hub and OTSL for
impairment. Under the equity method of accounting, an impairment loss would be recorded whenever a
decline in value of an equity investment below its carrying amount is determined to be other than
temporary. In judging other than temporary, we would consider the length of time and extent to
which the fair value of the investment has been less than the carrying amount of the equity
investment, the near-term and longer-term operating and financial prospects of the equity company
and our longer-term intent of retaining the investment in the entity. OTSL has generated a net
operating loss during 2006 which is an impairment indicator. As a result, we evaluated this
investment to determine whether a permanent loss in value had occurred. Based on this evaluation,
OTSL currently has the ability to sustain an earnings capacity which would justify the carrying
amount of the investment, and as a result there is no impairment at December 31, 2006.
Goodwill and Other Intangible Assets
We test for the impairment of goodwill on at least an annual basis. Intangible assets with
finite useful lives are amortized using the straight-line method over their useful lives.
Intangible assets that have indefinite useful lives are not amortized, but are tested for
impairment annually and when impairment indicators such as the nature of the assets, the future
economic benefit of the assets, any historical or future profitability measurements and other
external market conditions are present. Our goodwill impairment test involves a comparison of the
fair value of each of our reporting units with its carrying amount. The fair value is determined
using discounted cash flows and other market-related valuation models, such as earnings multiples
and comparable asset market values. We completed our annual goodwill impairment test as of
November 1, 2006. The changes in the carrying amount of goodwill by the applicable segments are as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracting |
|
|
Shelf |
|
|
|
|
|
|
|
|
|
Services |
|
|
Contracting |
|
|
Oil and Gas |
|
|
Total |
|
Balance at December 31, 2004 |
|
$ |
69,220 |
|
|
$ |
14,973 |
|
|
$ |
|
|
|
$ |
84,193 |
|
Acergy acquisition |
|
|
|
|
|
|
12,841 |
|
|
|
|
|
|
|
12,841 |
|
Helix RDS acquisition |
|
|
6,915 |
|
|
|
|
|
|
|
|
|
|
|
6,915 |
|
Tax and other adjustments |
|
|
(2,218 |
) |
|
|
|
|
|
|
|
|
|
|
(2,218 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005 |
|
|
73,917 |
|
|
|
27,814 |
|
|
|
|
|
|
|
101,731 |
|
Remington acquisition |
|
|
|
|
|
|
|
|
|
|
707,596 |
|
|
|
707,596 |
|
Seatrac acquisition |
|
|
7,415 |
|
|
|
|
|
|
|
|
|
|
|
7,415 |
|
Acergy acquisition adjustment |
|
|
|
|
|
|
(1,148 |
) |
|
|
|
|
|
|
(1,148 |
) |
Helix RDS acquisition adjustment |
|
|
2,634 |
|
|
|
|
|
|
|
|
|
|
|
2,634 |
|
Tax and other adjustments |
|
|
4,328 |
|
|
|
|
|
|
|
|
|
|
|
4,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006 |
|
$ |
88,294 |
|
|
$ |
26,666 |
|
|
$ |
707,596 |
|
|
$ |
822,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Of our total goodwill at December 31, 2006 and 2005, approximately $41.0 million and
$39.1 million, respectively, was expected to be deducted for tax purposes. None of our goodwill
was impaired based on the impairment test performed as of November 1, 2006. We will continue to
test our goodwill and other indefinite-lived intangible assets annually on a consistent measurement
date unless events occur or circumstances change between annual tests that would more likely than
not reduce the fair value of a reporting unit below its carrying amount.
Recertification Costs and Deferred Drydock Charges
Our Contracting Services and Shelf Contracting vessels are required by regulation to be
recertified after certain periods of time. These recertification costs are incurred while the
vessel is in
56
drydock. In addition, routine repairs and maintenance are performed and, at times,
major replacements
and improvements are performed. We expense routine repairs and maintenance as they are
incurred. We defer and amortize drydock and related recertification costs over the length of time
for which we expect to receive benefits from the drydock and related recertification, which is
generally 30 months. Vessels are typically available to earn revenue for the 30-month period
between drydock and related recertification processes. A drydock and related recertification
process typically lasts one to two months, a period during which the vessel is not available to
earn revenue. Major replacements and improvements, which extend the vessels economic useful life
or functional operating capability, are capitalized and depreciated over the vessels remaining
economic useful life. Inherent in this process are estimates we make regarding the specific cost
incurred and the period that the incurred cost will benefit.
As of December 31, 2006 and 2005, capitalized deferred drydock charges (included in Other
Assets, Net, see Note 7 Detail of Certain Accounts) totaled $26.4 million and $18.3 million,
respectively. During the years ended December 31, 2006, 2005 and 2004, drydock amortization expense
was $12.0 million, $8.9 million and $4.9 million, respectively.
Accounting for Decommissioning Liabilities
We account for our decommissioning liabilities in accordance with Statement of Financial
Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. This statement
requires that the fair value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred. The associated asset retirement costs are capitalized as part of
the carrying cost of the asset. Our asset retirement obligations consist of estimated costs for
dismantlement, removal, site reclamation and similar activities associated with our oil and gas
properties. An asset retirement obligation and the related asset retirement cost are recorded when
an asset is first constructed or purchased. The asset retirement cost is determined and discounted
to present value using a credit-adjusted risk-free rate. After the initial recording the liability
is increased for the passage of time, with the increase being reflected as accretion expense in the
statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability
and the amounts continue to be amortized over the useful life of the related long-lived asset.
SFAS No. 143 calls for measurements of asset retirement obligations to include, as a component
of expected costs, an estimate of the price that a third party would demand, and could expect to
receive, for bearing the uncertainties and unforeseeable circumstances inherent in the obligations,
sometimes referred to as a market-risk premium. To date, the oil and gas industry has no examples
of credit-worthy third parties who are willing to assume this type of risk, for a determinable
price, on major oil and gas production facilities and pipelines. Therefore, because determining
such a market-risk premium would be an arbitrary process, we excluded it from our SFAS No. 143
estimates.
The following table describes the changes in our asset retirement obligations for the year
ended 2006 and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Asset retirement obligation at January 1, |
|
$ |
121,352 |
|
|
$ |
82,030 |
|
Liability incurred during the period |
|
|
40,442 |
|
|
|
36,119 |
|
Liability settled during the period |
|
|
(6,669 |
) |
|
|
(1,913 |
) |
Revision in estimated cash flows |
|
|
3,929 |
|
|
|
(583 |
) |
Accretion expense (included in depreciation and amortization) |
|
|
8,617 |
|
|
|
5,699 |
|
|
|
|
|
|
|
|
Asset retirement obligations at December 31, |
|
$ |
167,671 |
|
|
$ |
121,352 |
|
|
|
|
|
|
|
|
Revenue Recognition
Revenues from Contracting Services and Shelf Contracting are derived from contracts that are
typically of short duration. These contracts contain either lump-sum turnkey provisions or
provisions for specific time, material and equipment charges, which are billed in accordance with
the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts.
57
Revenues generated from specific time, materials and equipment contracts are generally earned
on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In
connection with these contracts, we may receive revenues for mobilization of equipment and
personnel. In connection with new contracts, revenues related to mobilization are deferred and
recognized over the period in which contracted services are performed using the straight-line
method. Incremental costs incurred directly for mobilization of equipment and personnel to the
contracted site, which typically consist of materials, supplies and transit costs, are also
deferred and recognized over the period in which contracted services are performed using the
straight-line method. Our policy to amortize the revenues and costs related to mobilization on a
straight-line basis over the estimated contract service period is consistent with the general pace
of activity, level of services being provided and dayrates being earned over the service period of
the contract. Mobilization costs to move vessels when a contract does not exist are expensed as
incurred.
Revenue on significant turnkey contracts is recognized on the percentage-of-completion method
based on the ratio of costs incurred to total estimated costs at completion. In determining whether
a contract should be accounted for using the percentage-of-completion method, we consider whether:
|
|
|
the customer provides specifications for the construction of facilities or for
the provision of related services; |
|
|
|
|
we can reasonably estimate our progress towards completion and our costs; |
|
|
|
|
the contract includes provisions as to the enforceable rights regarding the
goods or services to be provided, consideration to be received and the manner
and terms of payment; |
|
|
|
|
the customer can be expected to satisfy its obligations under the contract; and |
|
|
|
|
we can be expected to perform our contractual obligations. |
Under the percentage-of-completion method, we recognize estimated contract revenue based on
costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of
materials and labor, productivity, scheduling and other factors affect the total estimated costs.
Additionally, external factors, including weather and other factors outside of our control, may
also affect the progress and estimated cost of a projects completion and, therefore, the timing of
income and revenue recognition. We routinely review estimates related to our contracts and reflect
revisions to profitability in earnings on a current basis. If a current estimate of total contract
cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is
first determined. We recognize additional contract revenue related to claims when the claim is
probable and legally enforceable.
Unbilled revenue represents revenue attributable to work completed prior to period end that
has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2006 and 2005
are expected to be billed and collected within one year.
We record revenues from the sales of crude oil and natural gas when delivery to the customer
has occurred and title has transferred. This occurs when production has been delivered to a
pipeline or a barge lifting has occurred. We may have an interest with other producers in certain
properties. In this case, we use the entitlements method to account for sales of production.
Under the entitlements method, we may receive more or less than our entitled share of production.
If we receive more than our entitled share of production, the imbalance is treated as a liability.
If we receive less than our entitled share, the imbalance is recorded as an asset. As of December
31, 2006, the net imbalance was a $200,000 asset and was included in Other Current Assets ($4.7
million) and Accrued Liabilities ($4.5 million) in the accompanying consolidated balance sheet.
Income Taxes
Deferred income taxes are based on the differences between financial reporting and tax bases
of assets and liabilities. We utilize the liability method of computing deferred income taxes. The
liability method is based on the amount of current and future taxes payable using tax rates and
laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws
and rates in the countries in which operations are conducted and income is earned. A valuation
allowance for deferred tax assets is recorded when it is more likely than not that some or all of
the benefit from the deferred tax asset will not be realized. We consider the undistributed
earnings of our principal non-U.S. subsidiaries
58
to be permanently reinvested.
Foreign Currency
The functional currency for our foreign subsidiaries, Well Ops (U.K.) Limited and Helix RDS,
is the applicable local currency (British Pound), and the functional currency of Seatrac is its
applicable local currency (Australian Dollar). Results of operations for these subsidiaries are
translated into U.S. dollars using average exchange rates during the period. Assets and
liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rate
in effect at December 31, 2006 and 2005 and the resulting translation adjustment, which was an
unrealized gain (loss) of $17.6 million and $(11.4) million, respectively, is included in
accumulated other comprehensive income (loss), a component of shareholders equity. Beginning in
2004, deferred taxes were not provided on foreign currency translation adjustments for operations
where we consider our undistributed earnings of our principal non-U.S. subsidiaries to be
permanently reinvested. As a result, cumulative deferred taxes on translation adjustments totaling
approximately $6.5 million were reclassified from noncurrent deferred income taxes and accumulated
other comprehensive income. All foreign currency transaction gains and losses are recognized
currently in the statements of operations. These amounts for the years ended December 31, 2006 and
2005 were not material to our results of operations or cash flows.
Canyon Offshore, our ROV subsidiary, has operations in the United Kingdom and Asia Pacific.
Further, FDI has operations in Southeast Asia. Canyon and FDI conduct the majority of their
operations in these regions in U.S. dollars which is considered to be their functional currency.
When currencies other than the U.S. dollar are to be paid or received, the resulting transaction
gain or loss is recognized in the statements of operations. These amounts for the year ended
December 31, 2006, 2005 and 2004, respectively, were not material to our results of operations or
cash flows.
Derivative Instruments and Hedging Activities
We are currently exposed to market risk in three major areas: commodity prices, interest rates
and foreign currency exchange risks. Our price risk management activities involve the use of
derivative financial instruments to hedge the impact of market price risk exposures primarily
related to our oil and gas production, variable interest rate exposure and foreign exchange
currency risks. All derivatives are reflected in our balance sheet at fair value, unless otherwise
noted.
We engage primarily in cash flow hedges. Hedges of cash flow exposure are entered into to
hedge a forecasted transaction or the variability of cash flows to be received or paid related to a
recognized asset or liability. Changes in the derivative fair values that are designated as cash
flow hedges are deferred to the extent that they are effective and are recorded as a component of
accumulated other comprehensive income until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a cash flow hedges change in value is recognized immediately
in earnings.
We formally document all relationships between hedging instruments and hedged items, as well
as our risk management objectives, strategies for undertaking various hedge transactions and the
methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments
are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also
assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that
are used in the hedging transactions are highly effective in offsetting changes in cash flows of
its hedged items. We discontinue hedge accounting if we determine that a derivative is no longer
highly effective as a hedge, or it is probable that a hedged transaction will not occur. If hedge
accounting is discontinued, deferred gains or losses on the hedging instruments are recognized in
earnings immediately.
Commodity Hedges
The fair value of hedging instruments reflects our best estimate and is based upon exchange or
over-the-counter quotations whenever they are available. Quoted valuations may not be available
due to location differences or terms that extend beyond the period for which quotations are
available. Where quotes are not available, we utilize other valuation techniques or models to
estimate market values.
59
These modeling techniques require us to make estimations of future prices,
price correlation and market
volatility and liquidity. Our actual results may differ from its estimates, and these
differences can be positive or negative.
During 2006 and 2005, we entered into various cash flow hedging costless collar contracts to
stabilize cash flows relating to a portion of our expected oil and gas production. All of these
qualified for hedge accounting. The aggregate fair value of the hedge instruments was a net asset
(liability) of $5.2 million and $(13.4) million as of December 31, 2006 and 2005, respectively.
For the years ended December 31, 2006, 2005 and 2004, we recorded unrealized gains (losses) of
approximately $12.1 million, $(8.1) million and $846,000, net of taxes of $6.5 million, $4.4
million and $456,000, respectively, in accumulated other comprehensive income (loss), a component
of shareholders equity, as these hedges were highly effective. The balance in the cash flow hedge
adjustments account is recognized in earnings when the related hedged item is sold. During 2006,
2005 and 2004, we reclassified approximately $9.0 million, $(14.1) million and $(11.1) million,
respectively, of gains (losses) from other comprehensive income to Oil and Gas revenues upon the
sale of the related oil and gas production.
Hedge ineffectiveness related to cash flow hedges was a loss of $1.8 million, net of taxes of
$951,000 in 2005 as reported in that periods earnings as a reduction of oil and gas productive
revenues. Hedge ineffectiveness resulted from our inability to deliver contractual oil and gas
production in 2005 due primarily to the effects of Hurricanes Katrina and Rita. No hedge
ineffectiveness related to our commodity hedges were recognized in 2006 and 2004.
As of December 31, 2006, we had the following volumes under derivative contracts related to
our oil and gas producing activities totaling 1,170 MBbl of oil and 9,500 MMbtu of natural gas:
|
|
|
|
|
|
|
|
|
Instrument |
|
Average |
|
Weighted |
Production Period |
|
Type |
|
Monthly Volumes |
|
Average Price |
Crude Oil: |
|
|
|
|
|
|
January 2007 December 2007 |
|
Collar |
|
98 MBbl |
|
$49.74 $66.96 |
|
|
|
|
|
|
|
Natural Gas: |
|
|
|
|
|
|
January 2007 June 2007 |
|
Collar |
|
650,000 MMBtu |
|
$ 7.85 $12.90 |
July 2007 December 2007 |
|
Collar |
|
933,333 MMBtu |
|
$ 7.50 $10.13 |
Changes in NYMEX oil and gas strip prices would, assuming all other things being equal, cause
the fair value of these instruments to increase or decrease inversely to the change in NYMEX
prices.
As of December 31, 2006, we had oil forward sales contracts for the period from January 2007
through June 2007. The contracts cover an average of 40 MBbl per month at a weighted average price
of $70.83. In addition, we had natural gas forward sales contracts for the period from January
2007 through June 2007. The contracts cover an average of 750,833 MMbtu per month at a weighted
average price of $9.49. Hedge accounting does not apply to these contracts.
Subsequent to December 31, 2006, we entered into two additional natural gas costless collars.
The first collar covers 300,000 MMBtu per month at a price of $7.50 to $9.92 for the period from
October through December 2007. The second collar is for the period of January through March 2008.
The collar covers 600,000 MMBtu per month at a price of $7.50 to $12.55. We also entered into an
oil costless collar for 60 MBbl per month for the period from January 2008 to June 2008 at a
weighted average price of $55.00 to $73.58.
Interest Rate Hedge
As the rates for our Term Loan are subject to market influences and will vary over the term of
the credit agreement, we entered into various cash flow hedging interest rate swaps to stabilize
cash flows relating to a portion of our interest payments for our Term Loan. The interest rate
swaps were effective October 3, 2006. These interest rate swaps qualify for hedge accounting. See
"Note 10 Long-Term Debt below for a detailed discussion of our Term Loan. The aggregate fair
value of the hedge
60
instruments was a net liability of $531,000 as of December 31, 2006. For the year ended
December 31, 2006, these hedges were highly effective.
Foreign Currency Hedge
In December 2006, we entered into various foreign exchange forwards to stabilize expected cash
outflows relating to a shipyard contract where the contractual payments are denominated in euros.
These forward contracts qualify for hedge accounting. Under the forward contracts, we have hedged
payments totaling 18.0 million to be settled in June and December 2007 at exchange rates of 1.3255
and 1.3326, respectively. The aggregate fair value of the hedge instruments was a net liability of
$184,000 as of December 31, 2006. For the year ended December 31, 2006, these hedges were highly
effective.
Earnings per Share
Basic earnings per share (EPS) is computed by dividing the net income available to common
shareholders by the weighted-average shares of outstanding common stock. The calculation of diluted
EPS is similar to basic EPS, except the denominator includes dilutive common stock equivalents and
the income included in the numerator excludes the effects of the impact of dilutive common stock
equivalents, if any. The computation of basic and diluted per share amounts for the years ended
December 31, 2006, 2005 and 2004 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
Income |
|
|
Shares |
|
|
Income |
|
|
Shares |
|
|
Income |
|
|
Shares |
|
Earnings applicable per common share Basic |
|
$ |
344,036 |
|
|
|
84,613 |
|
|
$ |
150,114 |
|
|
|
77,444 |
|
|
$ |
79,916 |
|
|
|
76,409 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
|
|
|
|
449 |
|
|
|
|
|
|
|
772 |
|
|
|
|
|
|
|
609 |
|
Restricted shares |
|
|
|
|
|
|
160 |
|
|
|
|
|
|
|
240 |
|
|
|
|
|
|
|
|
|
Employee stock purchase plan |
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible Senior Notes |
|
|
|
|
|
|
1,009 |
|
|
|
|
|
|
|
118 |
|
|
|
|
|
|
|
|
|
Convertible preferred stock |
|
|
3,358 |
|
|
|
3,631 |
|
|
|
2,454 |
|
|
|
3,631 |
|
|
|
2,743 |
|
|
|
2,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings applicable per common share Diluted |
|
$ |
347,394 |
|
|
|
89,874 |
|
|
$ |
152,568 |
|
|
|
82,205 |
|
|
$ |
82,659 |
|
|
|
79,062 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were no antidilutive stock options in the years ended December 31, 2006, 2005 and
2004, respectively. In addition, approximately 1,020,000 shares attributable to the convertible
preferred stock were excluded in the year ended December 31, 2004, calculation of diluted EPS, as
the effect was antidilutive. Net income for the diluted earnings per share calculation for the
years ended December 31, 2006, 2005 and 2004 were adjusted to add back the preferred stock
dividends and accretion on the 3.6 million shares, 3.6 million shares and 2.0 million shares,
respectively.
Stock Based Compensation Plans
Prior to January 1, 2006, we used the intrinsic value method of accounting for our stock-based
compensation. Accordingly, no compensation expense was recognized when the exercise price of an
employee stock option was equal to the common share market price on the grant date and all other
terms were fixed. In addition, under the intrinsic value method, on the date of grant for
restricted shares, we recorded unearned compensation (a component of shareholders equity) that
equaled the product of the number of shares granted and the closing price of our common stock on
the business day prior to the grant date, and expense was recognized over the vesting period of
each grant on a straight-line basis.
61
The following table reflects our pro forma results if the fair value method had been used for
the accounting for these plans for the years ended December 31, 2005 and 2004 (in thousands, except
per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
Net income applicable to common shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As Reported |
|
$ |
150,114 |
|
|
$ |
79,916 |
|
Add back: Stock-based compensation cost
included in reported net income, net of taxes |
|
|
914 |
|
|
|
|
|
Deduct: Total stock-based compensation cost
determined under the fair value method, net of tax |
|
|
(2,566 |
) |
|
|
(2,368 |
) |
|
|
|
|
|
|
|
Pro Forma |
|
$ |
148,462 |
|
|
$ |
77,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share: |
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
As reported |
|
$ |
1.94 |
|
|
$ |
1.05 |
|
|
|
|
|
|
|
|
Pro forma |
|
$ |
1.92 |
|
|
$ |
1.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
As reported |
|
$ |
1.86 |
|
|
$ |
1.03 |
|
|
|
|
|
|
|
|
Pro forma |
|
$ |
1.84 |
|
|
$ |
1.00 |
|
|
|
|
|
|
|
|
For the purposes of pro forma disclosures, the fair value of each option grant was
estimated on the date of grant using the Black-Scholes option pricing model with the following
weighted average assumptions used in 2004: expected dividend yields of 0%; expected lives of ten
years, risk-free interest rate assumed to be 4.0%, and expected volatility to be 56%. There were
no stock option grants in 2006 and 2005. The fair value of shares issued under the Employee Stock
Purchase Plan was based on the 15% discount received by the employees. The weighted average per
share fair value of the options granted in 2004 was $8.80. No stock options were granted in 2005.
The estimated fair value of the options is amortized to pro forma expense over the vesting period.
See Note 13 Employee Benefit Plans for discussion of our stock compensation.
Accounting for Sales of Stock by Subsidiary
We recognize a gain or loss upon the direct sale of equity by our subsidiaries if the sales
price differs from our carrying amount, provided that the sale of such equity is not part of a
broader corporate reorganization. See Note 3 for discussion of CDIs initial public offering.
Consolidation of Variable Interest Entities
Effective December 31, 2003, we adopted and applied the provisions of FIN 46 for all variable
interest entities. FIN 46 requires the consolidation of variable interest entities in which an
enterprise absorbs a majority of the entitys expected losses, receives a majority of the entitys
expected residual returns, or both, as a result of ownership, contractual or other financial,
interests in the entity. See Note 9 related to our consolidated variable interest entities.
62
Fair Value of Financial Instruments
Our financial instruments consist of cash and cash equivalents, short-term investments,
accounts receivable, accounts payable and our long-term debts. The carrying amount of cash and
cash equivalents, short-term investments, accounts receivable and accounts payable approximate fair
value due to the highly liquid nature of these short-term instruments. The carrying amount and
estimated fair value of our debt instruments, including current maturities as of December 31, 2006
and 2005 were as follows (amount in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Value |
|
Value |
|
Value |
|
Value |
Term Loan(1) |
|
$ |
832,900 |
|
|
$ |
834,462 |
|
|
$ |
|
|
|
$ |
|
|
Cal Dive Revolving Credit Facility(2) |
|
|
201,000 |
|
|
|
201,000 |
|
|
|
|
|
|
|
|
|
Convertible Senior Notes(1) |
|
|
300,000 |
|
|
|
378,780 |
|
|
|
300,000 |
|
|
|
433,695 |
|
MARAD Debt(3) |
|
|
131,286 |
|
|
|
126,691 |
|
|
|
134,926 |
|
|
|
132,565 |
|
Loan Notes(4) |
|
|
11,146 |
|
|
|
11,146 |
|
|
|
5,393 |
|
|
|
5,393 |
|
|
|
|
(1) |
|
The fair values of these instruments were based on quoted market prices as of December
31, 2006 and 2005, if applicable. |
|
(2) |
|
The carrying value of the Cal Dive revolving credit facility approximates fair value as
of December 31, 2006. |
|
(3) |
|
The fair value of the MARAD debt was determined by a third-party evaluation of the
remaining average life and outstanding principal balance of the MARAD indebtedness as
compared to other government guaranteed obligations in the market place with similar terms. |
|
(4) |
|
The carrying value of the loan notes approximates fair value as the maturity dates of
these securities are less than one year. |
Major Customers and Concentration of Credit Risk
The market for our products and services is primarily the offshore oil and gas industry. Oil
and gas companies make capital expenditures on exploration, drilling and production operations
offshore, the level of which is generally dependent on the prevailing view of the future oil and
gas prices, which have been characterized by significant volatility. Our customers consist
primarily of major, well-established oil and pipeline companies and independent oil and gas
producers and suppliers. We perform ongoing credit evaluations of our customers and provide
allowances for probable credit losses when necessary. The percent of consolidated revenue of major
customers was as follows: 2006 Louis Dreyfus Energy Services (10%) and Shell Offshore, Inc.
(10%); 2005 Louis Dreyfus Energy Services (10%) and Shell Trading (US) Company (10%); and 2004
Louis Dreyfus Energy Services (11%) and Shell Trading (US) Company (10%). All of these
customers were purchasers of our oil and gas production.
Recently Issued Accounting Principles
In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of FASB Statement No. 109 (FIN 48), which clarifies the accounting for
uncertainty in income taxes recognized in accordance with FASB Statement No. 109, Accounting for
Income Taxes (SFAS No. 109). FIN 48 clarifies the application of SFAS No. 109 by defining
criteria that an individual tax position must meet for any part of the benefit of that position to
be recognized in the financial statements. Additionally, FIN 48 provides guidance on the
measurement, derecognition, classification and disclosure of tax positions, along with accounting
for the related interest and penalties. The provisions of FIN 48 are effective for fiscal years
beginning after December 15, 2006, with the cumulative effect of the change in accounting principle
recorded as an adjustment to opening retained earnings. On January 1, 2007, we adopted the
provisions of FIN 48 and the impact of the adoption was immaterial on our financial position,
results of operations and cash flows.
In September 2006, the FASB issued Statement No. 157, Fair Value Measurements (SFAS No.
157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in
accordance with generally accepted accounting principles and expands disclosures about fair value
measurements. The provisions of SFAS No. 157 are effective for fiscal years beginning after
November 15, 2007. We are currently evaluating the impact, if any, of this statement.
63
Note 3 Initial Public Offering of Cal Dive International, Inc.
In December 2006, we contributed the assets of our Shelf Contracting segment into Cal Dive
International, Inc., our then wholly owned subsidiary. Cal Dive subsequently sold 22,173,000
shares of its common stock in an initial public offering and distributed the net proceeds of $264.4
million to us as a dividend. In connection with the offering, CDI also entered into a $250 million
revolving credit facility. In December 2006, Cal Dive borrowed $201 million under the facility and
distributed $200 million of the proceeds to us as a dividend. For additional information related
to the Cal Dive credit facilities, see Note 10 Long-term Debt below. We recognized an
after-tax gain of $96.5 million, net of taxes of $126.6 million as a result of these transactions.
We plan to use the proceeds for general corporate purposes.
In connection with the offering, together with shares issued to CDI employees immediately
after the offering, our ownership of CDI decreased to approximately 73.0%. Subject to market
conditions, we may sell additional shares of Cal Dive common stock in the future.
Further, in conjunction with the offering, the tax basis of certain CDIs tangible and
intangible assets was increased to fair value. The increased tax basis should result in additional
tax deductions available to CDI over a period of two to five years. Under the Tax Matters Agreement
with CDI, to the extent CDI generates taxable income sufficient to realize the additional tax
deductions, it will be required to pay us 90% of the amount of tax savings actually realized from
the step-up of the assets. As of December 31, 2006, we have a long-term receivable from CDI of
approximately $11.3 million related to the Tax Matters Agreement. For additional information
related to the Tax Matters Agreement, see Note 11 Income Taxes.
Note 4 Acquisition of Remington Oil and Gas Corporation
On July 1, 2006, we acquired 100% of Remington, an independent oil and gas exploration and
production company headquartered in Dallas, Texas, with operations concentrated in the onshore and
offshore regions of the Gulf Coast, for approximately $1.4 billion in cash and stock and the
assumption of $349.6 million of liabilities. The merger consideration was 0.436 of a share of our
common stock and $27.00 in cash for each share of Remington common stock. On July 1, 2006, we
issued 13,032,528 shares of our common stock to Remington stockholders and funded the cash portion
of the Remington acquisition (approximately $806.8 million) and transaction costs (approximately
$18.5 million) through a credit agreement (see Note 10Long-Term Debt below).
The Remington acquisition was accounted for as a business combination with the acquisition
price allocated to the assets acquired and liabilities assumed based upon their estimated fair
values, with excess being recorded in goodwill. The following table summarizes the estimated
preliminary fair values of the assets acquired and liabilities assumed at the date of acquisition
(in thousands):
|
|
|
|
|
Current assets |
|
$ |
154,336 |
|
Property and equipment |
|
|
859,722 |
|
Goodwill |
|
|
707,596 |
|
Other intangible assets(1) |
|
|
6,800 |
|
|
|
|
|
Total assets acquired |
|
$ |
1,728,454 |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
125,662 |
|
Deferred income taxes |
|
|
201,317 |
|
Decommissioning liabilities (including current portion) |
|
|
20,832 |
|
Other non-current liabilities |
|
|
1,800 |
|
|
|
|
|
Total liabilities assumed |
|
$ |
349,611 |
|
|
|
|
|
|
|
|
|
|
Net assets acquired |
|
$ |
1,378,843 |
|
|
|
|
|
|
|
|
(1) |
|
The intangible asset is related to a favorable drilling rig contract
and several non-compete agreements between the Company and certain
members of senior management. The preliminary |
64
|
|
|
|
|
fair value of the
drilling rig contract was $5.0 million and that amount will be
reclassified into property and equipment if drilling of certain
exploratory wells is successful. If drilling is unsuccessful, the
intangible asset will be expensed in the period drilling is determined
to be unsuccessful. The preliminary fair value of the non-compete
agreements was $1.8 million, which will be amortized over the term of
the agreements (three years) on a straight-line basis. |
Certain data necessary to complete our final purchase price allocation is not yet available,
and includes, but is not limited to, final tax returns that provide the underlying tax basis of
Remingtons assets and liabilities at July 1, 2006, valuation of certain proved and unproved oil
and gas properties and identification and valuation of potential intangible assets. We expect to
complete our valuation of assets and liabilities (including deferred taxes) for the purpose of
allocation of the total purchase price amount to assets acquired and liabilities assumed during the
twelve-month period following the acquisition date. Any future change in the value of net assets
up until the one year period has expired will be offset by a corresponding increase or decrease in
goodwill.
The results of the Remington acquisition are included in the accompanying statements of
operations since the date of purchase in our Oil and Gas segment . See pro forma combined
operating results of the Company and the Remington acquisition for the years ended December 31,
2006 and 2005 in Note 6 Other Acquisitions below.
Note 5 Oil and Gas Properties
We follow the successful efforts method of accounting for our interests in oil and gas
properties. Under the successful efforts method, the costs of successful wells and leases
containing productive reserves are capitalized. Costs incurred to drill and equip development
wells, including unsuccessful development wells, are capitalized. Costs incurred relating to
unsuccessful exploratory wells are expensed in the period the drilling is determined to be
unsuccessful.
At December 31, 2006, we had capitalized approximately $50 million of exploratory drilling
costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may
be charged against earnings in future periods if management determines that commercial quantities
of hydrocarbons have not been discovered or that future appraisal drilling or development
activities are not likely to occur. The following table provides a detail of our capitalized
exploratory project costs at December 31, 2006 and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Huey |
|
$ |
11,378 |
|
|
$ |
|
|
Noonan |
|
|
27,824 |
|
|
|
|
|
Castleton (part of Gunnison) |
|
|
7,070 |
|
|
|
5,844 |
|
Tulane |
|
|
|
|
|
|
6,170 |
|
Other |
|
|
3,711 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
49,983 |
|
|
$ |
12,014 |
|
|
|
|
|
|
|
|
The following table reflects net changes in suspended exploratory well costs during the
year ended December 31, 2006, 2005 and 2004 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Beginning balance at January 1, |
|
$ |
12,014 |
|
|
$ |
1,052 |
|
|
$ |
|
|
Additions pending the determination of proved reserves |
|
|
138,679 |
|
|
|
10,962 |
|
|
|
1,052 |
|
Reclassifications to proved properties |
|
|
(62,375 |
) |
|
|
|
|
|
|
|
|
Charged to dry hole expense |
|
|
(38,335 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance at December 31, |
|
$ |
49,983 |
|
|
$ |
12,014 |
|
|
$ |
1,052 |
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, all of these exploratory well costs had been capitalized for a
period of one year or less, except for Castleton. We are not the operator of Castleton.
65
Further, the following table details the components of exploration expense for the years ended
December 31, 2006, 2005 and 2004 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Delay rental and geological and geophysical costs |
|
$ |
4,780 |
|
|
$ |
6,465 |
|
|
$ |
|
|
Dry hole expense |
|
|
38,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration expense |
|
$ |
43,115 |
|
|
$ |
6,465 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
In addition, in 2006, we expensed inspection and repair costs related to damages sustained by
Hurricanes Katrina and Rita for our oil and gas properties totaling approximately $16.8 million,
partially offset by $9.7 million of insurance recoveries received. In 2005, we expensed
approximately $7.1 million of inspection and repair costs as a result damages caused by these
hurricanes. No insurance recoveries were received in 2005.
We agreed to participate in the drilling of an exploratory well (Tulane prospect) that was
drilled in the first quarter of 2006. This prospect targeted reserves in deeper sands, within the
same trapping fault system, of a currently producing well. In March 2006, mechanical difficulties
were experienced in the drilling of this well, and after further review, the well was plugged and
abandoned. The total estimated cost to us of approximately $21.7 million was charged to earnings
during the year ended December 31, 2006. We continue to evaluate various options with the operator
for recovering the potential resources. Further, in the third quarter of 2006, we expensed
approximately $15.9 million of exploratory drilling costs related to two deep shelf properties
(acquired in the Remington acquisition which were in process prior to July 1, 2006) in which we
determined commercial quantities of hydrocarbons were not discovered.
In August 2006, we acquired a 100% working interest in the Typhoon oil field (Green Canyon
Blocks 236/237), the Boris oil field (Green Canyon Block 282) and the Little Burn oil field (Green
Canyon Block 238) for assumption of certain decommissioning liabilities. We have received SOP
approval from the MMS. We will also have farm-in rights on five near-by blocks where three
prospects have been identified in the Typhoon mini-basin. Following the acquisition of the Typhoon
field and MMS approval, we renamed the field Phoenix. We expect to deploy a minimal floating
production system in mid-2008 in the Phoenix field.
In December 2006, we acquired a 100% working interest in the Camelot oil field in the U. K.
North Sea for assumption of certain decommissioning liabilities totaling approximately $7.6
million. We have commenced existing field rejuvenation and expect first production in 2007.
In March 2005, we acquired a 30% working interest in a proved undeveloped field in Atwater
Block 63 (Telemark) of the Deepwater Gulf of Mexico for cash and assumption of certain
decommissioning liabilities. In December 2005, we were advised by Norsk Hydro USA Oil and Gas,
Inc. (Norsk Hydro) that Norsk Hydro would not pursue its development plan for the deepwater
discovery. As a result, we acquired a 100% working interest and operatorship in April 2006
following a non-consent to our plan of development by Norsk Hydro. Our interest in this property
and surrounding fields was sold in July 2006 for $15 million in cash and we also retained a
reservation of an overriding royalty interest in the Telemark development. We recorded a gain of
$2.2 million in the third quarter of 2006 related to this sale.
In June 2005, we acquired a mature property package on the Gulf of Mexico shelf from Murphy
Oil Corporation (Murphy). The acquisition cost included both cash ($163.5 million) and the
assumption of the estimated abandonment liability from Murphy of approximately $32.0 million (a
non-cash investing activity). The acquisition represented essentially all of Murphys Gulf of
Mexico Shelf properties consisting of eight operated and eleven non-operated fields. We estimated
proved reserves of the acquisition to be approximately 75 Bcfe. The results of the acquisition are
included in the accompanying statements of operations since the date of purchase. See pro forma
combined operating results of the Company and the Murphy acquisition for the years ended December
31, 2006 and 2005 in Note 6 Other Acquisitions below.
66
Our oil and gas activities in the United States are regulated by the federal government and
require significant third-party involvement, such as refinery processing and pipeline
transportation. We record revenue from our offshore properties net of royalties paid to the MMS.
Royalty fees paid totaled approximately $41.0 million, $34.0 million and $26.7 million for the
years ended December 31, 2006, 2005 and 2004, respectively. In accordance with federal regulations
that require operators in the Gulf of Mexico to post an area wide bond of $3 million, the MMS has
allowed us to fulfill such bonding requirements through an insurance policy.
Note 6 Other Acquisitions
2006
Fraser Diving International Ltd.
In July 2006, we acquired the business of Singapore-based Fraser Diving International Ltd for
an aggregate purchase price of approximately $29.3 million, subject to post-closing adjustments,
and the assumption of $2.2 million of liabilities. FDI owns six portable saturation diving systems
and 15 surface diving systems that operate primarily in Southeast Asia, the Middle East, Australia
and the Mediterranean. Included in the purchase price is a payment of $2.5 million made in
December 2005 to FDI for the purchase of one of the portable saturation diving systems. The
acquisition was accounted for as a business combination with the acquisition price allocated to the
assets acquired and liabilities assumed based upon their estimated fair values. The following
table summarizes the estimated preliminary fair values of the assets acquired and liabilities
assumed at the date of acquisition (in thousands):
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2,332 |
|
Accounts receivable |
|
|
1,817 |
|
Prepaid expenses and deposits |
|
|
691 |
|
Portable saturation diving systems and surface diving systems |
|
|
23,685 |
|
Diving support equipment, support facilities and other equipment |
|
|
3,004 |
|
|
|
|
|
Total assets acquired |
|
$ |
31,529 |
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
2,243 |
|
|
|
|
|
|
|
|
|
|
Net assets acquired |
|
$ |
29,286 |
|
|
|
|
|
The allocation of the purchase price was based upon preliminary valuations. Estimates
and assumptions are subject to change upon the receipt and managements review of the final
valuations. The primary areas of the purchase price allocation that are not yet finalized relate
to post closing purchase price adjustments. The final valuation of net assets is expected to be
completed no later than one year from the acquisition date. The results of FDI are included in the
accompanying consolidated statements of operations in our Shelf Contracting segment since the date
of purchase. Pro forma combined operating results for the years ended December 31, 2006 and 2005
(adjusted to reflect the results of operations of FDI prior to its acquisition) are not provided
because the pre-acquisition results related to FDI were not material to the historical results of
the Company.
Seatrac Pty, Ltd.
In October 2006, we acquired a 58% interest in Seatrac for total consideration of
approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1
million paid to existing shareholders and $3.4 million for subscription of new Seatrac shares. We
have changed the name of this entity to Well Ops SEA Pty Ltd. The proceeds from the newly issued
shares were used by the entity to pay down existing indebtedness of approximately $1.9 million and
to provide funding for capital expenditures of $1.5 million. Seatrac is a subsea well intervention
and engineering services company located in Perth, Australia. Under the terms of the purchase
agreement, we will be obligated to purchase the remaining 42% of the shares outstanding from the
existing shareholders for $9.1 million upon Seatracs successfully obtaining a significant
commercial contract. In the event that the conditions required for the additional purchase are not
met, we will be under no obligation to purchase the remaining 42% of Seatrac. The option period to
acquire the remaining 42% expires on June 30, 2007. In addition,
67
the agreement with the existing shareholders provides for an earnout period of five years from
the closing date for the purchase of the remaining 42% of Seatrac. If during this five-year period
Seatrac achieves certain financial performance objectives, the shareholders will be entitled to
additional consideration of approximately $4.6 million.
The acquisition was accounted for as a business combination with the acquisition price
allocated to the assets acquired and liabilities assumed based upon their estimated fair values.
The following table summarizes our portion of the estimated preliminary fair values of the assets
acquired and liabilities assumed at the date of acquisition (in thousands):
|
|
|
|
|
Cash and cash equivalents |
|
$ |
1,215 |
|
Other current assets |
|
|
1,906 |
|
Property and equipment |
|
|
4,218 |
|
Goodwill |
|
|
7,136 |
|
Total assets acquired |
|
$ |
14,475 |
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
1,810 |
|
|
|
|
|
|
|
|
|
|
Net assets acquired |
|
$ |
12,665 |
|
|
|
|
|
The allocation of the purchase price was based upon preliminary valuations. Estimates
and assumptions are subject to change upon the receipt and managements review of the final
valuations. The primary areas of the purchase price allocation that are not yet finalized relate
to the identification and valuation of potential intangible assets and valuation of certain
equipment. The final valuation of net assets is expected to be completed no later than one year
from the acquisition date. The results of Seatrac are included in the accompanying consolidated
statements of operations in our Contracting Services segment since the date of purchase. Pro forma
combined operating results for the year ended December 31, 2006 and 2005 (adjusted to reflect the
results of operations of Seatrac prior to its acquisition) are not provided because the
pre-acquisition results related to Seatrac were not material to the historical results of the
Company.
Caesar
In January 2006, our wholly owned subsidiary, Vulcan Marine Technology LLC (Vulcan),
acquired the Caesar (formerly known as the Baron), a four year old mono-hull vessel originally
built for the cable lay market, for approximately $27.5 million in cash. The vessel was under
charter to a third-party until mid January 2007. After the completion of the charter, the vessel
was in transit to a shipyard in China where we plan to convert the vessel into a deepwater pipelay
asset. The vessel is 485 feet long and already has a state-of-the-art, class 2, dynamic positioning
system. The conversion program will primarily involve the installation of a conventional S lay
pipelay system together with a main crane and a significant upgrade to the accommodation
capability. A conversion team has already been assembled with a base at Rotterdam, the Netherlands,
and the vessel is likely to enter service during the second half of 2007. The estimated cost to
acquire and convert the vessel will be approximately $137.5 million. We have entered into an
agreement with the third party that leased the vessel, whereby the third party has an option to
purchase up to 49% of Vulcan for consideration totaling the proportionate share of the cost of the
vessel plus the actual cost of conversion (conversion cost is estimated to be $110 million). The
third party must make all contributions to Vulcan on or before March 31, 2007.
2005
Torch Offshore, Inc.
In a bankruptcy auction held in June 2005, we were the high bidder for seven vessels,
including the Express, and a portable saturation system for approximately $85.9 million, subject to
the terms of an amended and restated asset purchase agreement, executed in May 2005, with Torch.
This transaction received regulatory approval, including completion of a review pursuant to a
Second Request from the U.S. Department of Justice, in August 2005 and subsequently closed. The
total purchase price for the Torch vessels was approximately $85.9 million, including certain costs
incurred related to the transaction. The acquisition was an asset purchase with the acquisition
price allocated to the assets acquired based
68
upon their estimated fair values. All of the assets acquired, except for the Express
(Contracting Services segment) are included in the Shelf Contracting segment. The results of the
acquired vessels are included in the accompanying consolidated statements of operations since the
date of the purchase, August 31, 2005.
Acergy US Inc.
In April 2005, we agreed to acquire the diving and shallow water pipelay assets of Acergy that
operate in the waters of the Gulf of Mexico and Trinidad. The transaction included: seven diving
support vessels; two diving and pipelay vessels (the Kestrel and the DLB 801); a portable
saturation diving system; various general diving equipment and Louisiana operating bases at the
Port of Iberia and Fourchon. All of the assets are included in the Shelf Contracting segment. The
transaction required regulatory approval, including the completion of a review pursuant to a Second
Request from the U.S. Department of Justice. On October 18, 2005, we received clearance from the
U.S. Department of Justice to close the purchase from Acergy. Under the terms of the clearance, we
were required to divest two diving support vessels and a portable saturation diving system from the
combined asset package acquired through this transaction and the Torch transaction which closed in
August 2005. We have since disposed of one diving support vessel and a portable saturation diving
system prior to December 31, 2006, and disposed of the remaining diving support vessel in January
2007. These assets were included in assets held for sale totaling approximately $700,000 and $7.8
million as of December 31, 2006 and 2005, respectively. On November 1, 2005, we closed the
transaction to purchase the Acergy diving assets operating in the Gulf of Mexico. We acquired the
DLB 801 in January 2006 for approximately $38.0 million and the Kestrel for approximately $39.9
million in March 2006.
The Acergy acquisition was accounted for as a business combination with the acquisition price
allocated to the assets acquired and liabilities assumed based upon their fair values, with the
excess being recorded as goodwill. The final valuation of net assets was completed in the second
quarter of 2006. The total transaction value for all of the assets was approximately $124.3
million. The allocation of the Acergy purchase prices was as follows (in thousands):
|
|
|
|
|
Vessels |
|
$ |
94,484 |
|
Goodwill |
|
|
11,693 |
|
Portable saturation system and diving equipment |
|
|
9,494 |
|
Facilities, land and leasehold improvements |
|
|
4,314 |
|
Customer relationships intangible asset(1) |
|
|
3,698 |
|
Materials and supplies |
|
|
631 |
|
|
|
|
|
Total |
|
$ |
124,314 |
|
|
|
|
|
|
|
|
(1) |
|
The customer relationship intangible asset is amortized over eight years on a
straight-line basis, or approximately $463,000 per year. |
The results of the acquired assets are included in the accompanying consolidated
statements of operations in our Shelf Contracting segment since the date of the purchase. Pro
forma combined operating results adjusted to reflect the results of operations of the DLB 801 and
the Kestrel prior to their acquisition from Acergy in January and March 2006, respectively, are not
provided because the 2006 pre-acquisition results related to these vessels were immaterial to our
historical results. See pro forma combined operating results of the Company and the Acergy
acquisition for the years ended December 31, 2006 and 2005 below.
Subsequent to our purchase of the DLB 801, we sold a 50% interest in the vessel in January
2006 for approximately $19.0 million. We received $6.5 million in cash in 2005 and a $12.5 million
interest-bearing promissory note in 2006. The balance of the promissory note as of December 31,
2006 was $1.5 million. We expect to collect the remaining balance. Subsequent to the sale of the
50% interest, we entered into a 10-year charter lease agreement with the purchaser, in which the
lessee has an option to purchase the remaining 50% interest in the vessel beginning in January
2009. This lease was accounted for as an operating lease. Included in our lease accounting
analysis was an assessment of the likelihood of the lessee performing under the full term of the
lease. The carrying amount of the DLB 801 at December 31, 2006, was approximately $17.3 million.
In addition, if the lessee exercises the purchase option under the lease agreement, the lessee is
able to credit $2.35 million of its lease
69
payments per year against purchase price for the remaining 50% interest in the DLB 801 not
already owned. If the lessee elects not to exercise its option to purchase the remaining 50%
interest in the vessel, minimum future rentals to be received on this lease are $66.2 million.
Helix Energy Limited
On November 3, 2005, we acquired Helix Energy Limited for approximately $32.7 million
(approximately $27.1 million in cash, including transaction costs, and $5.6 million, at time of
acquisition, in two year, variable rate notes payable to certain former owners), offset by $3.4
million of cash acquired. Helix Energy Limited is an Aberdeen, UK based provider of reservoir and
well technology services to the upstream oil and gas industry with offices in London, Kuala Lumpur
(Malaysia) and Perth (Australia). The acquisition was accounted for as a business purchase with
the acquisition price allocated to the assets acquired and liabilities assumed as follows (in
thousands):
|
|
|
|
|
Cash and cash equivalents |
|
$ |
3,417 |
|
Other current assets |
|
|
9,786 |
|
Property and equipment, net |
|
|
632 |
|
Intangibles with definite useful lives(1) |
|
|
10,459 |
|
Trade name intangible(2) |
|
|
6,309 |
|
Goodwill |
|
|
9,549 |
|
|
|
|
|
Total assets acquired |
|
$ |
40,152 |
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
4,920 |
|
Deferred tax liability |
|
|
2,532 |
|
|
|
|
|
|
Net assets acquired |
|
$ |
32,700 |
|
|
|
|
|
|
|
|
(1) |
|
Intangibles with definite useful lives include the following: |
|
|
|
$1.1 million of patented technology, which is amortized over 20 years on a
straight-line basis, or approximately $56,800 per year; |
|
|
|
|
$6.9 million of customer relationship, which is amortized over 12 years on a
straight-line basis, or approximately $578,000 per year; and |
|
|
|
|
$2.4 million of non-compete intangible asset, which is amortized over 3.5 years
on a straight-line basis, or approximately $683,000 per year. |
(2) |
|
The trade name intangible has an indefinite useful life. It is not amortized,
but is tested for impairment at least annually or when impairment indicators are
present. |
Resulting amounts are included in the Contracting Services segment. The final valuation of net
assets was completed in 2006. The results of Helix Energy Limited are included in the accompanying
statements of operations since the date of the purchase.
Pro forma combined operating results of the Company and the Remington, Murphy and Acergy
acquisitions for the years ended December 31, 2006 and 2005 were presented as if the acquisitions
had been completed as of January 1, 2005. The unaudited pro forma combined results were as follows
(in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006(1) |
|
2005 |
Net revenues |
|
$ |
1,509,539 |
|
|
$ |
1,337,648 |
|
Income before income taxes(2) |
|
|
591,455 |
|
|
|
252,543 |
|
Net income(2) |
|
|
337,885 |
|
|
|
168,316 |
|
Net income applicable to common shareholders(2) |
|
|
334,527 |
|
|
|
165,862 |
|
Earnings per common share(2): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
3.67 |
|
|
$ |
1.83 |
|
Diluted |
|
$ |
3.51 |
|
|
$ |
1.77 |
|
|
|
|
(1) |
|
Includes approximately $11.5 million of severance and
incentive compensation expense, and approximately $20.6 million of
non-cash stock compensation expense for vesting of stock options
and restricted shares incurred by Remington in June 30, 2006.
|
|
(2) |
|
Includes pre-tax gain of approximately $223.1 million related
to CDIs initial public offering. The |
70
|
|
|
|
|
taxes associated with this
gain was approximately $126.6 million. |
Note 7 Details of Certain Accounts (in thousands)
Other current assets consisted of the following as of December 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Other receivables |
|
$ |
3,882 |
|
|
$ |
1,386 |
|
Prepaid insurance |
|
|
17,320 |
|
|
|
8,791 |
|
Other prepaids |
|
|
9,174 |
|
|
|
4,391 |
|
Spare parts inventory |
|
|
3,660 |
|
|
|
3,628 |
|
Current deferred tax assets |
|
|
3,706 |
|
|
|
8,861 |
|
Hedging assets |
|
|
5,202 |
|
|
|
|
|
Gas imbalance |
|
|
4,739 |
|
|
|
3,888 |
|
Current notes receivable |
|
|
1,500 |
|
|
|
1,500 |
|
Assets held for sale |
|
|
698 |
|
|
|
7,936 |
|
Other |
|
|
11,651 |
|
|
|
12,534 |
|
|
|
|
|
|
|
|
|
|
$ |
61,532 |
|
|
$ |
52,915 |
|
|
|
|
|
|
|
|
Other assets, net, consisted of the following as of December 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Restricted cash |
|
$ |
33,676 |
|
|
$ |
27,010 |
|
Deposits |
|
|
524 |
|
|
|
4,594 |
|
Deferred drydock expenses, net |
|
|
26,405 |
|
|
|
18,285 |
|
Deferred financing costs |
|
|
28,257 |
|
|
|
18,714 |
|
Intangible assets with definite lives |
|
|
20,783 |
|
|
|
14,707 |
|
Intangible asset with indefinite life |
|
|
6,922 |
|
|
|
6,074 |
|
Other |
|
|
1,344 |
|
|
|
1,490 |
|
|
|
|
|
|
|
|
|
|
$ |
117,911 |
|
|
$ |
90,874 |
|
|
|
|
|
|
|
|
Accrued liabilities consisted of the following as of December 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Accrued payroll and related benefits |
|
$ |
42,381 |
|
|
$ |
27,982 |
|
Royalties payable |
|
|
67,822 |
|
|
|
46,555 |
|
Current decommissioning liability |
|
|
28,766 |
|
|
|
15,035 |
|
Hedging liability |
|
|
184 |
|
|
|
8,814 |
|
Deposits |
|
|
|
|
|
|
10,000 |
|
Accrued interest |
|
|
15,579 |
|
|
|
2,610 |
|
Other |
|
|
44,918 |
|
|
|
27,468 |
|
|
|
|
|
|
|
|
|
|
$ |
199,650 |
|
|
$ |
138,464 |
|
|
|
|
|
|
|
|
Note 8 Equity Investments
In June 2002, we formed Deepwater Gateway, L.L.C. with Enterprise, in which we each own a 50%
interest, to design, construct, install, own and operate a tension leg platform (TLP) production
hub primarily for Anadarko Petroleum Corporations Marco Polo field discovery in the Deepwater Gulf
of Mexico. Our share of the construction costs was approximately $120 million. Our investment in
Deepwater Gateway totaled $119.3 million and $117.2 million as of December 31, 2006 and 2005,
respectively. Included in the investment account was capitalized interest and insurance paid by us
totaling approximately $1.7 and $1.7 million, respectively. In August 2002, Enterprise and we
completed a limited recourse project financing for this venture. In accordance with terms of the
term loan, Deepwater
71
Gateway had the right to repay the principal amount plus any accrued interest due under its
term loan at any time without penalty. Deepwater Gateway repaid the term loan in full in March
2005.
In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise.
Independence Hub will own the Independence Hub platform to be located in Mississippi Canyon block
920 in a water depth of 8,000 feet. We account for our investment in Independence Hub under the
equity method of accounting. Our investment was $82.7 million and $50.8 million as of December 31,
2006 and 2005, respectively. Our total investment is expected to be approximately $87 million.
Further, we are party to a guaranty agreement with Enterprise to the extent of our ownership in
Independence Hub. The agreement states, among other things, that we and Enterprise guarantee
performance under the Independence Hub Agreement between Independence Hub and the producers group
of exploration and production companies up to $426 million, plus applicable attorneys fees and
related expenses. We have estimated the fair value of our share of the guaranty obligation to be
immaterial at December 31, 2006 and 2005 based upon the remote possibility of payments being made
under the performance guarantee.
In July 2005, we acquired a 40% minority ownership interest in OTSL in exchange for our DP
DSV, Witch Queen. Our investment in OTSL totaled $10.9 million and $11.5 million at December 31,
2006 and 2005, respectively, and is part of our Shelf Contracting segment. OTSL provides marine
construction services to the oil and gas industry in and around Trinidad and Tobago, as well as the
U.S. Gulf of Mexico. OTSL qualified as a variable interest entity (VIE) under FIN 46. We have
determined that we were not the primary beneficiary of OTSL and, thus, have not consolidated the
financial results of OTSL. We account for our investment in OTSL under the equity method of
accounting.
Further, in conjunction with our investment in OTSL, we entered into a one year, unsecured
$1.5 million working capital loan, initially bearing interest at 6% per annum, with OTSL. Interest
is due quarterly beginning September 30, 2005 with a lump sum principal payment originally due to
us on June 30, 2006. We agreed to extend the lump sum principal payment due date and increased the
interest rate to three-month LIBOR plus 4.0%. The note was repaid in January 2007.
In the third and fourth quarters of 2005 and first quarter of 2006, OTSL contracted the Witch
Queen to us for certain services performed in the U.S. Gulf of Mexico. We incurred costs
associated with the contract with OTSL totaling approximately $7.7 million and $11.1 million in
2006 and 2005, respectively. The charter ended in March 2006.
Under the equity method of accounting, an impairment loss would be recorded whenever a decline
in value of an equity investment below its carrying amount was determined to be other than
temporary. In judging other than temporary, we would consider the length of time and extent to
which the fair value of the investment has been less than the carrying amount of the equity
investment, the near-term and longer-term operating and financial prospects of the equity company
and our longer-term intent of retaining the investment in the entity. We have reported a net loss
of $487,000 for the year ended December 31, 2006 related to our investment in OTSL. This net loss
was an impairment indicator. However, we believe the current trend is temporary and have
determined that the fair value of this investment, based on an estimate of its discounted cash
flows, exceeds its carrying amount. As a result, there was no impairment at December 31, 2006.
72
We made the following contributions to our equity investments during the years ended December
31, 2006, 2005 and 2004 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Deepwater Gateway, L.L.C.(1) |
|
$ |
|
|
|
$ |
72,000 |
|
|
$ |
20,615 |
|
Independence Hub, LLC |
|
|
25,578 |
|
|
|
39,060 |
|
|
|
10,585 |
|
OTSL(2) |
|
|
|
|
|
|
8,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
25,578 |
|
|
$ |
119,460 |
|
|
$ |
31,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Contribution made in the year ended December 31, 2005 related to Deepwater Gateway
was for the repayment of our portion of the term loan for Deepwater Gateway. Upon
repayment of the loan, our $7.5 million restricted cash in 2005 was released from
escrow and the escrow agreement was terminated. |
|
(2) |
|
Includes non-cash contribution of the Witch Queen in 2005 of $6.7 million (net of
$296,000 of transaction costs). |
We received the following distributions from our equity investments during the years ended
December 31, 2006, 2005 and 2004 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Deepwater Gateway, L.L.C. |
|
$ |
16,250 |
|
|
$ |
21,100 |
|
|
$ |
7,500 |
|
Independence Hub, LLC |
|
|
|
|
|
|
|
|
|
|
|
|
OTSL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
16,250 |
|
|
$ |
21,100 |
|
|
$ |
7,500 |
|
|
|
|
|
|
|
|
|
|
|
Note 9 Consolidated Variable Interest Entities
In October 2006, we, along with Kommandor RØMØ, a Danish corporation, formed Kommandor, a
Delaware limited liability company, to initially convert a ferry vessel into a
dynamically-positioned construction services vessel. 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.
Our initial investment for our 50% interest in Kommandor was $15 million. Further, we have agreed
to provide a loan facility of up to $40 million and Kommandor RØMØ has agreed to loan $5 million to
the newly formed entity for purposes of completing the initial conversion. Kommandor has received
a commitment letter from a financial institution for term financing for $60 million of the initial
conversion upon delivery of the vessel under the bareboat charter. Proceeds from this financing
will be used to repay amounts loaned to Kommandor by us and Kommandor RØMØ. Conversion of the
vessel is expected to be completed in two phases. The first phase is expected to be completed by
the end of 2007. The second phase of the conversion is expected to be completed by mid 2008.
Estimated cost of conversion for the second phase is approximately $100 million, in which we expect
to participate 100%.
In addition, per the operating agreement, for a period of two months immediately following the
fifth anniversary of the completion of the initial conversion, we may purchase Kommandor RØMØs
membership interest at a value specified in the agreement (Helix Option Period). In addition,
for a period of two months starting from 30 days after the Helix Option Period, Kommandor RØMØ can
require us to purchase its share of the company at a value specified in the operating agreement.
We estimate the cash outlay to Kommandor RØMØ for its interest in Kommandor at the time the put or
call is exercised to be approximately $23.8 million.
Kommandor qualified as a VIE under FIN 46. We determined that we were the primary beneficiary
of Kommandor and, thus, have consolidated the financial results of Kommandor as of
73
December 31, 2006. The results of Kommandor are included in our Production Facilities
segment. Kommandor is a development stage enterprise since its formation in October 2006.
Note 10 Long-Term Debt
Senior Credit Facilities
On July 3, 2006, we entered into a Credit Agreement (the Credit Agreement) with Bank of
America, N.A., as administrative agent and as lender, together with the other lenders
(collectively, the Lenders). Under the Credit Agreement, we borrowed $835 million in a term loan
(the Term Loan) and may borrow revolving loans (the Revolving Loans) under a revolving credit
facility up to an outstanding amount of $300 million (the Revolving Credit Facility). In
addition, the Revolving Credit Facility may be used for issuances of letters of credit up to an
outstanding amount of $50 million. The proceeds from the Term Loan were used to fund the cash
portion of the Remington acquisition.
The Term Loan and the Revolving Loans (together, the Loans) will, at our election, bear
interest either in relation to Bank of Americas base rate or to LIBOR. The Term Loan or portions
thereof bear interest at one, three or six month LIBOR at our election plus a margin of 2.00%. Our
current election is to bear interest based on LIBOR. Our interest rate for year ended December 31,
2006 was approximately 7.4% (including the effects of our interest rate swaps). The Revolving
Loans or portions thereof bearing interest at LIBOR will bear interest based on one, three or six
month LIBOR at our election plus a margin ranging from 1.00% to 2.25%. Margins on the Revolving
Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Credit
Agreement.
The Term Loan matures on July 1, 2013 and is subject to scheduled principal payments of $2.1
million quarterly. The Revolving Loans mature on July 1, 2011. We may elect to prepay amounts
outstanding under the Term Loan without prepayment penalty, but may not reborrow any amounts
prepaid. We may prepay amounts outstanding under the Revolving Loans without prepayment penalty,
and may reborrow amounts prepaid prior to maturity. We did not have any amount outstanding under
the Revolving Loans at December 31, 2006. In addition, 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.
The Credit Agreement and the other documents entered into in connection with the Credit
Agreement (together, the Loan Documents) include terms, conditions and covenants that we consider
customary for this type of transaction. The covenants include restrictions on the Companys and our
subsidiaries ability to grant liens, incur indebtedness, make investments, merge or consolidate,
sell or transfer assets and pay dividends. The credit facility also places certain annual and
aggregate limits on expenditures for acquisitions, investments in joint ventures and capital
expenditures. The Credit Agreement requires us to meet minimum financial ratios for interest
coverage, consolidated leverage and, until we achieve investment grade ratings from S&P and
Moodys, collateral coverage.
If we or any of our subsidiaries do not pay any amounts owed to the Lenders under the Loan
Documents when due, breach any other covenant to the Lenders or fail to pay other debt above a
stated threshold, in each case, subject to applicable cure periods, then the Lenders have the right
to stop making advances to us and to declare the Loans immediately due. The Credit Agreement
includes other events of default that are customary for this type of transaction. As of December
31, 2006, we were in compliance with these covenants.
The Loans and our other obligations to the Lenders under the Loan Documents are guaranteed by
all of our U.S. subsidiaries other than Cal Dive, and are secured by a lien on substantially all of
our assets and properties and all of the assets and properties of our U.S. subsidiaries, other than
those of Cal Dive. In addition, we have pledged a portion of the shares of our significant foreign
subsidiaries to the lenders as additional security. The Senior Credit Facilities also 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 however permit us to incur
unsecured indebtedness, and also provide for our subsidiaries to
74
incur project financing indebtedness (such as our MARAD loans) secured by the underlying
asset, provided that the indebtedness is not guaranteed by us.
As the rates for the Term Loan are subject to market influences and will vary over the term of
the agreement, we entered into various interest rate swaps for $200 million of notional value
effective as of October 3, 2006. These hedges are designated as cash flow hedges and qualify for
hedge accounting. Under the swaps we receive interest based on three-month LIBOR and pay interest
quarterly at an average annual fixed rate of 5.131% which began in October 2006. The objective of
the hedge is to eliminate the variability of cash flows in the interest payments for up to $200
million of our Term Loan. Changes in the cash flows of the interest rate swap are expected to
exactly offset the changes in cash flows (i.e., changes in interest rate payments) attributable to
fluctuations in LIBOR on up to $200 million of our Term Loan.
Cal Dive International, Inc. Revolving Credit Facility
In November 2006, CDI entered into a five-year $250 million revolving credit facility with
certain financial institutions. The loans mature in November 2011. Loans under this facility are
non-recourse to Helix. Loans under the revolving credit facility may consist of loans bearing
interest in relation to the Federal Funds Rate or to the lenders base rate, known as Base Rate
Loans, and loans bearing interest in relation to a LIBOR rate, known as LIBOR Rate Loans. Assuming
there is no event of default, Base Rate Loans will bear interest at a per annum rate equal to the
base rate plus a margin ranging from 0% to 0.5%, while LIBOR Rate Loans will bear interest at the
LIBOR rate plus a margin ranging from 0.625% to 1.75%.
The credit agreement and the other documents entered into in connection with the credit
agreement include terms and conditions, including covenants. The covenants include restrictions on
the CDIs ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell
or transfer assets and pay dividends. In addition, the credit agreement obligates CDI to meet
minimum financial requirements specified in the agreement. At December 31, 2006, CDI was in
compliance with all debt covenants. The credit facility is secured by vessel mortgages on five of
CDIs vessels, a pledge of all of the stock of all of CDIs domestic subsidiaries and 65% of the
stock of one of CDIs foreign subsidiaries, and a security interest in, among other things, all of
CDIs equipment, inventory, accounts and general tangible assets.
During December 2006, CDI borrowed $201 million under the revolving credit facility and
distributed $200 million of those proceeds to us as a dividend. At December 31, 2006, CDI had
outstanding debt of $201 million under this credit facility. CDI expects to use the remaining
availability under the revolving credit facility for working capital and other general corporate
purposes. We do not have access to any unused portion of CDIs revolving credit facility.
Convertible Senior Notes
On March 30, 2005, we issued $300 million of 3.25% Convertible Senior Notes due 2025
(Convertible Senior Notes) at 100% of the principal amount to certain qualified institutional
buyers. The Convertible Senior Notes are convertible into cash and, if applicable, shares of our
common stock based on the specified conversion rate, subject to adjustment. As a result of our two
for one stock split paid on December 8, 2005, effective as of December 2, 2005, the initial
conversion rate of the Convertible Senior Notes of 15.56, which was equivalent to a conversion
price of approximately $64.27 per share of common stock, was changed to 31.12 shares of common
stock per $1,000 principal amount of the Convertible Senior Notes, which is equivalent to a
conversion price of approximately $32.14 per share of common stock. We may redeem the
Convertible Senior Notes on or after December 20, 2012. Beginning with the period commencing on
December 20, 2012 to June 14, 2013 and for each six-month period thereafter, in addition to the
stated interest rate of 3.25% per annum, we will pay contingent interest of 0.25% of the market
value of the Convertible Senior Notes if, during specified testing periods, the average trading
price of the Convertible Senior Notes exceeds 120% or more of the principal value. In addition,
holders of the Convertible Senior Notes may require us to repurchase the notes at 100% of the
principal amount on each of December 15, 2012, 2015, and 2020, and upon certain events.
75
The Convertible Senior Notes can be converted prior to the stated maturity under the following
circumstances:
|
|
|
during any fiscal quarter (beginning with the quarter ended March 31, 2005) if the
closing sale price of our common stock for at least 20 trading days in the period of 30
consecutive trading days ending on the last trading day of the preceding fiscal quarter
exceeds 120% of the conversion price on that 30th trading day (i.e., $38.56 per share); |
|
|
|
|
upon the occurrence of specified corporate transactions; or |
|
|
|
|
if we have called the Convertible Senior Notes for redemption and the redemption has
not yet occurred. |
To the extent we do not have alternative long-term financing secured to cover such conversion
notice, the Convertible Senior Notes would be classified as a current liability in the accompanying
balance sheet.
In connection with any conversion, we will satisfy our obligation to convert the Convertible
Senior Notes by delivering to holders in respect of each $1,000 aggregate principal amount of notes
being converted a settlement amount consisting of:
|
|
|
cash equal to the lesser of $1,000 and the conversion value, and |
|
|
|
|
to the extent the conversion value exceeds $1,000, a number of shares equal to the
quotient of (A) the conversion value less $1,000, divided by (B) the last reported sale
price of our common stock for such day. |
The conversion value means the product of (1) the conversion rate in effect (plus any
applicable additional shares resulting from an adjustment to the conversion rate) or, if the
Convertible Senior Notes are converted during a registration default, 103% of such conversion rate
(and any such additional shares), and (2) the average of the last reported sale prices of our
common stock for the trading days during the cash settlement period. During 2006 and 2005, no
conversion triggers were met.
Approximately 1.0 million and 118,000 shares underlying the Convertible Senior Notes were
included in the calculation of diluted earnings per share for the year ended December 31, 2006 and
2005, respectively, because our weighted average share price for each period was above the
conversion price of approximately $32.14 per share. As a result, there would be a premium over the
principal amount, which is paid in cash, and the shares would be issued on conversion. The maximum
number of shares of common stock which may be issued upon conversion of the Convertible Senior
Notes is 13,303,770. In addition to the 13,303,770 shares of common stock registered, we registered
an indeterminate number of shares of common stock issuable upon conversion of the Convertible
Senior Notes by means of an antidilution adjustment of the conversion price pursuant to the terms
of the Convertible Senior Notes. Proceeds from the offering were used for general corporate
purposes including a capital contribution of $72 million, made in March 2005, to Deepwater Gateway
to enable it to repay its term loan, and strategic acquisitions in 2005 (Torch and Acergy vessels
and Murphy oil and gas properties).
MARAD Debt
At December 31, 2006 and 2005, $131.3 million and $134.9 million, respectively, was
outstanding on our long-term financing for construction of the Q4000. This U.S. Government
guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is
administered by the Maritime Administration (MARAD Debt). The MARAD Debt is payable in equal
semi-annual installments which began in August 2002 and matures 25 years from such date. The MARAD
Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt, and initially bore
interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points.
As provided for in the existing MARAD Debt agreements, in September 2005, we fixed the interest
rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date
(February 2027). In accordance with the MARAD Debt agreements, 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, 2006 and 2005, we were in compliance with
these covenants.
76
In September 2005, we entered into an interest rate swap agreement with a bank. The swap was
designated as a cash flow hedge of a forecasted transaction in anticipation of the refinancing of
the MARAD Debt from floating rate debt to fixed-rate debt that closed on September 30, 2005. The
interest rate swap agreement totaled an aggregate notional amount of $134.9 million with a fixed
interest rate of 4.695%. On September 30, 2005, we terminated the interest rate swap and received
cash proceeds of approximately $1.5 million representing a gain on the interest rate differential.
This gain was deferred and is being amortized over the remaining life of the MARAD Debt as an
adjustment to interest expense.
Other
In connection with the acquisition of Helix Energy Limited, we entered into a two-year note
payable to the former owners totaling approximately 3.1 million British Pounds, or approximately
$5.6 million, on November 3, 2005 (approximately $6.2 million and $5.4 million at December 31, 2006
and 2005, respectively). The notes bear interest at a LIBOR based floating rate with interest
payments due quarterly beginning January 1, 2006. Principal amounts are due in November 2007.
In August 2003, Canyon Offshore, Ltd. (a U.K. subsidiary COL) (with a parent guaranty
from Helix) completed a capital lease with a bank refinancing the construction costs of certain
assets. COL received proceeds of $12 million for the assets and agreed to pay the bank sixty
monthly installment payments of $217,174 (resulting in an implicit interest rate of 3.29%) and has
an option to purchase the assets at the end of the lease term for $1. No gain or loss resulted
from this transaction. The proceeds were used to reduce our revolving credit facility, which had
initially funded the construction costs of the assets. This transaction was accounted for as a
capital lease.
In connection with borrowings under our long-term debt financings described above, we paid
deferred financing cost of $11.8 million and $8.8 million during the years ended December 31, 2006
and 2005, respectively. Deferred financing costs of $28.3 million and $18.7 million are included
in Other Assets, Net (see Note 7 Detail of Certain Accounts) as of December 31, 2006 and
2005, respectively, and are being amortized over the life of the respective agreement.
Scheduled maturities of long-term debt and capital lease obligations outstanding as of
December 31, 2006 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving |
|
|
Convertible |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term |
|
|
Credit |
|
|
Senior |
|
|
MARAD |
|
|
Loan |
|
|
Capital |
|
|
|
|
|
|
Loan |
|
|
Facility |
|
|
Notes |
|
|
Debt |
|
|
Notes(1) |
|
|
Leases |
|
|
Total |
|
Less than one year |
|
$ |
8,400 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
3,823 |
|
|
$ |
11,146 |
|
|
$ |
2,519 |
|
|
$ |
25,888 |
|
One to two years |
|
|
8,400 |
|
|
|
|
|
|
|
|
|
|
|
4,014 |
|
|
|
|
|
|
|
1,505 |
|
|
|
13,919 |
|
Two to Three years |
|
|
8,400 |
|
|
|
|
|
|
|
|
|
|
|
4,214 |
|
|
|
|
|
|
|
|
|
|
|
12,614 |
|
Three to four years |
|
|
8,400 |
|
|
|
|
|
|
|
|
|
|
|
4,424 |
|
|
|
|
|
|
|
|
|
|
|
12,824 |
|
Four to five years |
|
|
8,400 |
|
|
|
201,000 |
|
|
|
|
|
|
|
4,645 |
|
|
|
|
|
|
|
|
|
|
|
214,045 |
|
Over five years |
|
|
790,900 |
|
|
|
|
|
|
|
300,000 |
|
|
|
110,166 |
|
|
|
|
|
|
|
|
|
|
|
1,201,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
832,900 |
|
|
|
201,000 |
|
|
|
300,000 |
|
|
|
131,286 |
|
|
|
11,146 |
|
|
|
4,024 |
|
|
|
1,480,356 |
|
Current maturities |
|
|
(8,400 |
) |
|
|
|
|
|
|
|
|
|
|
(3,823 |
) |
|
|
(11,146 |
) |
|
|
(2,519 |
) |
|
|
(25,888 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, less current maturities |
|
$ |
824,500 |
|
|
$ |
201,000 |
|
|
$ |
300,000 |
|
|
$ |
127,463 |
|
|
$ |
|
|
|
$ |
1,505 |
|
|
$ |
1,454,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes the $5 million loan provided by Kommandor RØMØ to Kommandor as of December 31,
2006. The loan is expected to be repaid at the completion of the initial conversion, which
is forecasted to be the end of 2007. As such, the entire loan amount is classified as
current. |
77
We had unsecured letters of credit outstanding at December 31, 2006 totaling
approximately $5.3 million. These letters of credit primarily guarantee various contract bidding
and insurance activities. The following table details our interest expense and capitalized
interest for the years ended December 31, 2006, 2005 and 2004 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Interest expense |
|
$ |
51,913 |
|
|
$ |
14,970 |
|
|
$ |
6,282 |
|
Interest income |
|
|
(6,259 |
) |
|
|
(5,917 |
) |
|
|
(439 |
) |
Capitalized interest |
|
|
(10,609 |
) |
|
|
(2,025 |
) |
|
|
(243 |
) |
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
$ |
35,045 |
|
|
$ |
7,028 |
|
|
$ |
5,600 |
|
|
|
|
|
|
|
|
|
|
|
Note 11 Income Taxes
We and our subsidiaries, including acquired companies from their respective dates of
acquisition, file a consolidated U.S. federal income tax return. At December 13, 2006, CDI was
separated from our tax consolidated group as a result of its initial public offering. As a result,
we are required to accrue income tax expense on our share of CDIs net income after the initial
public offering in all periods where we consolidate their operations. The deconsolidation of CDIs
net income after its initial public offering did not have a material impact on our consolidated
results of operations. We conduct our international operations in a number of locations that have
varying laws and regulations with regard to taxes. Management believes that adequate provisions
have been made for all taxes that will ultimately be payable. Income taxes have been provided
based on the US statutory rate of 35% adjusted for items which are allowed as deductions for
federal income tax reporting purposes, but not for book purposes. The primary differences between
the statutory rate and our effective rate were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
Statutory rate |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
Gain on subsidiary equity transaction |
|
|
8.0 |
|
|
|
|
|
|
|
|
|
Foreign provision |
|
|
(0.2 |
) |
|
|
|
|
|
|
0.9 |
|
Percentage depletion in excess of basis |
|
|
(0.1 |
) |
|
|
(0.7 |
) |
|
|
|
|
Research and development tax credits |
|
|
|
|
|
|
|
|
|
|
(1.3 |
) |
IRC Section 199 deduction |
|
|
(0.2 |
) |
|
|
(0.5 |
) |
|
|
|
|
Other |
|
|
|
|
|
|
(0.8 |
) |
|
|
(0.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective rate |
|
|
42.5 |
% |
|
|
33.0 |
% |
|
|
34.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of the provision for income taxes reflected in the statements of operations
consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Current |
|
$ |
199,921 |
|
|
$ |
32,291 |
|
|
$ |
988 |
|
Deferred |
|
|
57,235 |
|
|
|
42,728 |
|
|
|
42,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
257,156 |
|
|
$ |
75,019 |
|
|
$ |
43,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Domestic |
|
$ |
247,588 |
|
|
$ |
68,957 |
|
|
$ |
41,260 |
|
Foreign |
|
|
9,568 |
|
|
|
6,062 |
|
|
|
1,774 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
257,156 |
|
|
$ |
75,019 |
|
|
$ |
43,034 |
|
|
|
|
|
|
|
|
|
|
|
In 2006 and 2005, our oil and gas activities and certain construction activities
qualified for a tax deduction under Internal Revenue Code (IRC) Section 199. In addition, due to
our taxable income position at December 31, 2006 and 2005, the IRC allowed a deduction for
percentage depletion in excess of basis on our oil and gas activities.
78
As a result of the Remington acquisition on July 1, 2006, a deferred tax asset was recorded as
a part of the purchase price allocation to reflect the availability of approximately $65.2 million
of net operating loss carryforward as of the acquisition date. As a result of our taxable income
position during 2006, we were able to utilize $61.0 million of the net operating loss carryforward
at December 31, 2006. A valuation reserve was determined not to be necessary.
Deferred income taxes result from the effect of transactions that are recognized in different
periods for financial and tax reporting purposes. The nature of these differences and the income
tax effect of each as of December 31, 2006 and 2005 was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Depreciation |
|
$ |
416,762 |
|
|
$ |
159,360 |
|
Equity investments in production facilities |
|
|
30,723 |
|
|
|
28,264 |
|
Prepaid and other |
|
|
31,383 |
|
|
|
10,693 |
|
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
$ |
478,868 |
|
|
$ |
198,317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Net operating loss carryforward |
|
$ |
(3,888 |
) |
|
$ |
(2,079 |
) |
Decommissioning liabilities |
|
|
(33,367 |
) |
|
|
(26,915 |
) |
Reserves, accrued liabilities and other |
|
|
(8,775 |
) |
|
|
(10,537 |
) |
|
|
|
|
|
|
|
Total deferred tax assets |
|
$ |
(46,030 |
) |
|
$ |
(39,531 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
432,838 |
|
|
$ |
158,786 |
|
|
|
|
|
|
|
|
At December 31, 2006 and 2005, we had $4.9 million and $6.9 million of net operating losses,
respectively that were incurred in the United Kingdom. The utilization of these net operating
losses is restricted to the entity generating the loss. The U.K. losses have an indefinite
carryforward period.
We consider the undistributed earnings of our principal non-U.S. subsidiaries to be
permanently reinvested. At December 31, 2006 and 2005, our principal non-U.S. subsidiaries had
accumulated earnings and profits of approximately $20.3 million and a $4.3 million deficit,
respectively. We have not provided deferred U.S. income tax on the accumulated earnings and
profits.
In December 2006, we entered into the Tax Matters Agreement with CDI in connection with the
CDI initial public offering. The following is a summary of the material terms of the Tax Matters
Agreement:
|
|
|
Liability for Taxes. Each party has agreed to indemnify the other in respect of all
taxes for which it is responsible under the Tax Matters Agreement. We are generally
responsible for all federal, state, local and foreign income taxes that are imposed on or
are attributable to CDI or any of its subsidiaries for all tax periods (or portions
thereof) ending on or before CDIs initial public offering. CDI is generally responsible
for all federal, state, local and foreign income taxes that are imposed on or are
attributable to CDI or any of its subsidiaries for all tax periods (or portions thereof)
beginning after its initial public offering. CDI is also responsible for all taxes other
than income taxes imposed on or attributable to CDI or any of its subsidiaries for all tax
periods. |
|
|
|
|
Tax Benefit Payments. As a result of certain taxable income recognition by us in
conjunction with the CDI initial public offering, CDI will become entitled to certain tax
benefits that are expected to be realized by CDI in the ordinary course of its business and
otherwise would not have been available to CDI. These benefits are generally attributable
to increased tax deductions for amortization of tangible and intangible assets and to
increased tax basis in nonamortizable assets. Under the Tax Matters Agreement, for the next
ten years, CDI will be required to make annual payments to us equal to 90% of the amount of
taxes which CDI saves for each tax period |
79
|
|
|
as a result of these increased tax benefits. The timing of CDIs payments to us under the
Tax Matters Agreement will be determined with reference to when CDI actually realizes the
projected tax savings. This timing will depend upon, among other things, the amount of their
taxable income and the timing at which certain assets are sold or disposed. |
|
|
|
Preparation and Filing of Tax Returns. We will prepare and file all income tax returns
that include CDI or any of its subsidiaries if we are responsible for any portion of the
taxes reported on such tax returns. The Tax Matters Agreement also provides that we will
have the sole authority to respond to and conduct all tax proceedings (including tax
audits) relating to such income tax returns. |
For the year ended December 31, 2006, this agreement did not have a material impact on our
consolidated results of operations.
Note 12 Convertible Preferred Stock
On January 8, 2003, we completed the private placement of $25 million of a newly designated
class of cumulative convertible preferred stock (Series A-1 Cumulative Convertible Preferred Stock,
par value $0.01 per share) that is convertible into 1,666,668 shares of our common stock at $15 per
share. The preferred stock was issued to a private investment firm. Subsequently in June 2004,
the preferred stockholder exercised its existing right and purchased $30 million in additional
cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par
value $0.01 per share). In accordance with the January 8, 2003 agreement, the $30 million in
additional preferred stock is convertible into 1,964,058 shares of our common stock at $15.27 per
share. In the event the holder of the convertible preferred stock elects to redeem into our common
stock and our common stock price is below the conversion prices, unless we have elected to settle
in cash, the holder would receive additional shares above the 1,666,668 common shares (Series A-1
tranche) and 1,964,058 common shares (Series A-2 tranche). The incremental shares would be treated
as a dividend and reduce net income applicable to common shareholders.
The preferred stock has a minimum annual dividend rate of 4%, subject to adjustment, payable
quarterly in cash or common shares at our option. The dividend rate for the years ended December
31, 2006, 2005 and 2004 was 6.9%, 5.9% and 4.0%, respectively. We paid these dividends in 2006,
2005 and 2004 in cash. The holder may redeem the value of its original and additional investment in
the preferred shares to be settled in common stock at the then prevailing market price or cash at
our discretion. In the event we are unable to deliver registered common shares, we could be
required to redeem in cash.
The proceeds received from the sales of this stock, net of transaction costs, have been
classified outside of shareholders equity on the balance sheet below total liabilities. Prior to
the conversion, common shares issuable will be assessed for inclusion in the weighted average
shares outstanding for our diluted earnings per share using the if converted method based on the
lower of our share price at the beginning of the applicable period or the applicable conversion
price ($15.00 and $15.27).
Note 13 Employee Benefit Plans
Defined Contribution Plan
We sponsor a defined contribution 401(k) retirement plan covering substantially all of our
employees. Our contributions are in the form of cash and are determined annually as 50 percent of
each employees contribution up to 5 percent of the employees salary. Our costs related to this
plan totaled $2.3 million, $963,000 and $691,000 for the years ended December 31, 2006, 2005 and
2004, respectively.
Stock-Based Compensation Plans
We have three stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended
(the 1995 Incentive Plan), the 2005 Long-Term Incentive Plan (the 2005 Incentive Plan) and the
1998 Employee Stock Purchase Plan (the ESPP). Under the 1995 Incentive Plan, a maximum of
80
10% of the total shares of common stock issued and outstanding may be granted to key
executives and selected employees and non-employee members of the Board of Directors. Following
the approval by shareholders of the 2005 Incentive Plan on May 10, 2005, no further grants have
been or will be made under the 1995 Plan. The aggregate number of shares that may be granted under
the 2005 Incentive Plan is 6,000,000 shares (after adjustment for the December 8, 2005 two-for-one
stock split) of which 4,000,000 shares may be granted in the form of restricted stock or restricted
stock units and 2,000,000 shares may be granted in the form of stock options. The 1995 and 2005
Incentive Plans and the ESPP are administered by the Compensation Committee of the Board of
Directors, which in the case of the 1995 and 2005 Incentive Plans, determines the type of award to
be made to each participant, and as set forth in the related award agreement, the terms, conditions
and limitations applicable to each award. The committee may grant stock options, stock and cash
awards. Awards granted to employees under the 1995 and 2005 Incentive Plan typically vest 20% per
year for a five-year period (or in the case of certain stock option awards under the 1995 Incentive
Plan, 33% per year for a three-year period); if in the form of stock options, have a maximum
exercise life of ten years; and, subject to certain exceptions, are not transferable.
Prior to January 1, 2006, we used the intrinsic value method of accounting for our stock-based
compensation. Accordingly, no compensation expense was recognized when the exercise price of an
employee stock option was equal to the common share market price on the grant date and all other
terms were fixed. In addition, under the intrinsic value method, on the date of grant for
restricted shares, we recorded unearned compensation (a component of shareholders equity) that
equaled the product of the number of shares granted and the closing price of our common stock on
the business day prior to the grant date, and expense was recognized over the vesting period of
each grant on a straight-line basis.
On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (Revised
2004) Share-Based Payments (SFAS 123R) and began accounting for our stock-based compensation
plans under the fair value method. We continue to use the Black-Scholes option pricing model for
valuing share-based payments relating to stock options and recognize compensation cost on a
straight-line basis over the respective vesting period. No forfeitures were estimated for
outstanding unvested options and restricted shares as historical forfeitures have been immaterial.
We have selected the modified-prospective method of adoption. Under that transition method,
compensation cost recognized in 2006 included: a) compensation cost for all share-based payments
granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value, and
(b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on
the grant-date fair value. In addition to the compensation cost recognition requirements, tax
deduction benefits for an award in excess of recognized compensation cost is reported as a
financing cash flow rather than as an operating cash flow. The adoption did not have a material
impact on our consolidated results of operations, earnings per share and cash flows. There were no
stock option grants in 2006 or 2005.
Stock Options
The options outstanding at December 31, 2006, have exercise prices as follows: 163,000 shares
at $8.57; 67,510 shares at $9.32; 110,680 shares at $10.92; 73,000 shares at $10.94; 64,800 shares
at $11.00; 181,280 shares at $12.18; 70,400 shares at $13.91; and 152,400 shares ranging from $8.14
to $12.00, and a weighted average remaining contractual life of 5.75 years.
81
Options outstanding are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
|
|
|
Average |
|
|
|
|
|
Average |
|
|
|
|
|
|
Exercise |
|
|
|
|
|
Exercise |
|
|
|
|
|
Exercise |
|
|
Shares |
|
Price |
|
Shares |
|
Price |
|
Shares |
|
Price |
Options outstanding at beginning of year |
|
|
1,717,904 |
|
|
$ |
10.91 |
|
|
|
2,599,894 |
|
|
$ |
10.65 |
|
|
|
3,446,204 |
|
|
$ |
10.19 |
|
Granted |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
337,000 |
|
|
$ |
12.63 |
|
Exercised |
|
|
(792,394 |
) |
|
$ |
11.21 |
|
|
|
(858,070 |
) |
|
$ |
10.17 |
|
|
|
(1,119,818 |
) |
|
$ |
9.85 |
|
Terminated |
|
|
(42,440 |
) |
|
$ |
10.96 |
|
|
|
(23,920 |
) |
|
$ |
10.82 |
|
|
|
(63,492 |
) |
|
$ |
10.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of year |
|
|
883,070 |
|
|
$ |
10.86 |
|
|
|
1,717,904 |
|
|
$ |
10.91 |
|
|
|
2,599,894 |
|
|
$ |
10.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable end of year |
|
|
515,318 |
|
|
$ |
10.34 |
|
|
|
1,066,316 |
|
|
$ |
10.94 |
|
|
|
1,428,348 |
|
|
$ |
10.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2006, $1.4 million was recognized as compensation expense
related to stock options. No expense related to stock options was recognized in 2005 and 2004
under the intrinsic value method. The aggregate intrinsic value of the stock options exercised in
2006, 2005 and 2004 was approximately $21.3 million, $12.6 million and $5.3 million, respectively.
Future compensation cost associated with unvested options at December 31, 2006 totaled
approximately $1.8 million. The aggregate intrinsic value of options exercisable at December 31,
2006 was approximately $10.8 million. The weighted average vesting period related to nonvested
stock options at December 31, 2006 was approximately 1.7 years.
Restricted Shares
We grant restricted shares to members of our board of directors, key executives and selected
management employees. Compensation cost for each award is the product of market value of each
share and the number of shares granted. The following table summarizes information about our
restricted shares during the years ended December 31, 2006 and 2005 (no restricted shares were
granted prior to 2005):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
|
|
|
|
Grant Date |
|
|
|
|
|
|
|
|
|
|
|
|
Fair |
|
|
|
|
|
Grant Date |
|
|
Shares |
|
Value(1) |
|
Shares |
|
Fair Value(1) |
Restricted shares outstanding at beginning of year |
|
|
384,902 |
|
|
$ |
25.59 |
|
|
|
|
|
|
$ |
|
|
Granted |
|
|
497,450 |
|
|
$ |
37.07 |
|
|
|
388,350 |
|
|
$ |
25.56 |
|
Vested |
|
|
(66,865 |
) |
|
$ |
24.51 |
|
|
|
|
|
|
$ |
|
|
Forfeited |
|
|
(86,275 |
) |
|
$ |
36.04 |
|
|
|
(3,448 |
) |
|
$ |
21.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding at end of year, |
|
|
729,212 |
|
|
$ |
32.29 |
|
|
|
384,902 |
|
|
$ |
25.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the average grant date market value, which is based on the quoted market
price of the common stock on the business day prior to the date of grant. |
For the year ended December 31, 2005, the amounts granted were recorded as unearned
compensation, a component of shareholders equity and charged to expense over the respective
vesting periods on a straight-line basis. Amortization of unearned compensation totaled $1.4
million for the year ended December 31, 2005. The balance in unearned compensation at December 31,
2005 was $7.5 million and was reversed in January 2006 upon adoption of the fair value method. For
the year ended December 31, 2006, $6.3 million was recognized as compensation expense related to
restricted shares. Future compensation cost associated with unvested restricted stock awards at
December 31, 2006 totaled approximately $17.5 million. The weighted average vesting period related
to nonvested restricted stock awards at December 31, 2006 was approximately 3.8 years.
In January and February 2007, we granted certain key executives and select management
employees 675,190 restricted shares under the 2005 Long-Term Incentive Plan. The shares vest 20%
per year for a five-year period. The weighted average market value of the restricted shares was
$31.49 per share or $21.3 million. We also granted our outside directors 2,092 restricted shares.
The shares vest on January 1, 2009. The market value of the restricted shares was $31.37 per share
or $66,000.
82
Employee Stock Purchase Plan
Effective May 12, 1998, we adopted a qualified, non-compensatory ESPP, which allows employees
to acquire shares of common stock through payroll deductions over a six month period. The purchase
price is equal to 85 percent of the fair market value of the common stock on either the first or
last day of the subscription period, whichever is lower. Purchases under the plan are limited to 10
percent of an employees base salary. Under this plan 97,598, 79,878 and 93,580 shares of common
stock were purchased in the open market for our employees at a weighted-average share price of
$33.12, $23.11 and $13.58 during 2006, 2005 and 2004, respectively. For the year ended December
31, 2006, we recognized $1.6 million of compensation expense related to stock purchased under the
ESPP. No expenses related to the ESPP were recognized in 2005 and 2004 under the intrinsic value
method.
In January 2007, we issued 109,754 shares of our common stock to our employees under this plan
to satisfy the employee purchase period from July 1, 2006 to December 31, 2006, which increased our
common stock outstanding. We subsequently repurchased the same number of shares of our common
stock in the open market at $29.94 per share and reduced the number of shares of our common stock
outstanding.
Stock Compensation Modifications
Under our 1995 Incentive Plan and our 2005 Long-Term Incentive Plan, upon a stock recipients
termination of employment, which is defined as employment with us and any of our majority-owned
subsidiaries, any unvested restricted stock and stock options are forfeited immediately and all
unexercised vested options are forfeited, as specified under the applicable plan or agreement.
Ordinarily, once our beneficial ownership of CDI falls to 50% or below (the Trigger Date), the
options and unvested shares granted to CDI employees would be forfeited at such date under our
current plans. As part of the Employee Matters Agreement between us and CDI, which was executed
in December 2006, with respect to any employee who is a Cal Dive employee as of the date of the
IPO, we have agreed to extend the life of any vested and unexercised stock options to the earlier
of (1) the expiration of the general term of the option or (2) the later of (i) December 31 of the
calendar year in which the Trigger Date occurs, or (ii) the 15th day of the third month
after the expiration of the 60-day period commencing on the Trigger Date (135 days). To the extent
that any such employee would forfeit options because they have not vested as of such date, such
options will be accelerated and will vest at the Trigger Date. In addition, under the Employee
Matters Agreement, restricted stock awards granted to employees of CDI as of the IPO closing date
will continue under their present terms and the terms of the plans under which they were granted.
The modification date for these restricted stock and options occurred at the date the Employee
Matters Agreement was adopted. However, no accounting charge will occur until the Trigger Date
occurs and the impact of the modification, if any, can be measured.
Note 14 Shareholders Equity
Our amended and restated Articles of Incorporation provide for authorized Common Stock of
240,000,000 shares with no par value per share and 5,000,000 shares of preferred stock, $0.01 par
value per share, in one or more series.
In November 2005, our Board of Directors declared a two-for-one split of our common stock in
the form of a 100% stock distribution on December 8, 2005 to all holders of record at the close of
business on December 1, 2005. All share and per share data in these financial statements have been
restated to reflect the stock split.
The components of accumulated other comprehensive income (loss) as of December 31, 2006 and
2005 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Cumulative foreign currency translation adjustment |
|
$ |
24,580 |
|
|
$ |
6,979 |
|
Unrealized gain (loss) on hedges, net |
|
|
2,656 |
|
|
|
(8,708 |
) |
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss) |
|
$ |
27,236 |
|
|
$ |
(1,729 |
) |
|
|
|
|
|
|
|
83
Note 15 Stock Buyback Program
On June 28, 2006, our Board of Directors authorized us to discretionarily purchase up to $50
million of our common stock in the open market. In October and November 2006, we purchased
approximately 1.7 million shares under this program for a weighted average price of $29.86 per
share, or $50.0 million.
Note 16 Related Party Transactions
Cal Dive International, Inc.
Before the IPO of Cal Dive, we provided to Cal Dive certain management and administrative
services including: (i) accounting, treasury, payroll and other financial services; (ii) legal,
insurance and claims services; (iii) information systems, network and communication services; (iv)
employee benefit services (including direct third-party group insurance costs and 401(k)
contribution matching costs discussed below); and (v) corporate facilities management services.
Total allocated costs to Cal Dive for such services were approximately $16.5 million, $8.5 million
and $7.3 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Included in these costs are costs related to the participation by CDIs employees in our
employee benefit plans through December 31, 2006, including employee medical insurance and a
defined contribution 401(k) retirement plan. These costs were recorded as a component of operating
expenses and were approximately $5.8 million, $3.3 million and $2.5 million for the years ended
December 31, 2006, 2005 and 2004, respectively. Our defined contribution 401(k) retirement plan is
further disclosed in Note 13.
In addition, Cal Dive provided to us operational and field support services including: (i)
training and quality control services; (ii) marine administration services; (iii) supply chain and
base operation services; (iv) environmental, health and safety services; (v) operational facilities
management services; and (vi) human resources. Total allocated costs to us for such services were
approximately $5.6 million, $4.1 million and $3.2 million for the years ended December 31, 2006,
2005 and 2004, respectively. These amounts are eliminated in the accompanying consolidated
financial statements.
In contemplation of the IPO of CDI, we entered into intercompany agreements with CDI that
address the rights and obligations of each respective company, including a Master Agreement, a
Corporate Services Agreement, an Employee Matters Agreement and a Tax Matters Agreement. The Master
Agreement describes and provides a framework for the separation of our business from CDIs
business, allocates liabilities (including those potential liabilities related to litigation)
between the parties, allocates responsibilities and provides standards for each of the parties
conduct going forward (e.g., coordination regarding financial reporting), and sets forth the
indemnification obligations of each party. In addition, the Master Agreement provides us with a
preferential right to use a specified number of CDIs vessels in accordance with the terms of such
agreement.
Pursuant to the Corporate Services Agreement, each party agrees to provide specified services
to the other party, including administrative and support services for the time period specified
therein. Generally after we cease to own 50% or more of the total voting power of CDI common
stock, all services may be terminated by either party upon 60 days notice, but a longer notice
period is applicable for selected services. Each of the services shall be provided in exchange for
a monthly charge as calculated for each service (based on relative revenues, number of users for a
particular service, or other specified measure). In general, under the Corporate Services Agreement
we provide CDI with services related to the tax, treasury, audit, insurance (including claims) and
information technology functions; CDI provides us with services related to the human resources,
training and orientation functions, and certain supply chain and environmental, health and safety
services.
Pursuant to the Employee Matters Agreement, except as otherwise provided, CDI generally
accepts and assumes all employment related obligations with respect to all individuals who are
employees of CDI as of the IPO closing date, including expenses related to existing options
and restricted
84
stock. Those employees are entitled to retain their Helix stock options and
restricted stock grants under their original terms except as mandated by applicable law. The
Employee Matters Agreement also permits CDI employees to participate in our Employee Stock Purchase
Plan for the offering period that ends June 30, 2007, and CDI agrees to pay us at the end of the
offering period the fair market value of the shares of our stock purchased by such employees.
Pursuant to the Tax Matters Agreement , we are generally responsible for all federal, state,
local and foreign income taxes that are attributable to CDI for all tax periods ending on the IPO;
CDI is generally responsible for all such taxes beginning after the IPO. In addition, the
agreement provides that for a period of up to ten years, CDI is required to make annual payments to
us equal to 90% of tax benefits derived by CDI from tax basis adjustments resulting from the Boot
gain recognized by us as a result of the distributions made to us as part of the IPO transaction.
See Note 11 Income Taxes for more detailed disclosure of the Tax Matters Agreement.
Other
In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico
prospect of Kerr-McGee Oil & Gas Corp. Financing for the exploratory costs of approximately $20
million was provided by an investment partnership (OKCD Investments, Ltd. or OKCD), the investors
of which include current and former Helix senior management, in exchange for a revenue interest
that is an overriding royalty interest of 25% of Helixs 20% working interest. Production began in
December 2003. Payments to OKCD from us totaled $34.6 million, $28.1 million and $20.3 million in
the years ended December 31, 2006, 2005 and 2004, respectively. Our Principal Executive Officer, as
a Class A limited partner of OKCD, personally owns approximately 67% of the partnership. Other
executive officers of the Company own approximately 6% combined of the partnership. In 2000, OKCD
also awarded Class B limited partnership interests to key Helix employees.
In connection with the acquisition of Helix Energy Limited, we entered into two-year notes
payable to former owners totaling approximately 3.1 million British Pounds, or approximately $5.6
million, on November 3, 2005 (approximately $6.2 million and $5.4 million at December 31, 2006 and
2005). The notes bear interest at a LIBOR based floating rate with payments due quarterly
beginning January 31, 2006. Principal amounts are due in November 2007.
Note 17 Commitments and Contingencies
Lease Commitments
We lease several facilities, ROVs and a vessel under noncancelable operating leases. Future
minimum rentals under these leases are approximately $63.0 million at December 31, 2006 with $32.2
million due in 2007, $10.6 million in 2008, $10.1 million in 2009, $3.0 million in 2010, $2.4
million in 2011 and $4.7 million thereafter. Total rental expense under these operating leases was
approximately $25.3 million, $23.4 million and $8.9 million for the years ended December 31, 2006,
2005 and 2004, respectively.
Insurance
We carry Hull and Increased Value insurance which provides coverage for physical damage to an
agreed amount for each vessel. The deductibles are based on the value of the vessel with a maximum
deductible of $1.0 million on the Q4000 and $500,000 on the Intrepid, Seawell, Express and Kestrel.
Other vessels carry deductibles between $250,000 and $350,000. We also carry Protection and
Indemnity (P&I) insurance which covers liabilities arising from the operation of the vessels and
General Liability insurance which covers liabilities arising from construction operations. The
deductible on both the P&I and General Liability is $100,000 per occurrence. Onshore employees are
covered by Workers Compensation. Offshore employees, including divers and tenders and marine
crews, are covered by Maritime Employers Liability insurance policy which covers Jones Act
exposures and includes a deductible of $100,000 per occurrence plus a $1.0 million annual
aggregate. In addition to the liability policies named above, we carry various layers of Umbrella
Liability for total limits of $300,000,000 excess
of primary limits. Our self-insured retention on our medical and health benefits program for
employees is
85
$130,000 per participant.
We incur workers compensation and other insurance claims in the normal course of business,
which management believes are covered by insurance. Our insurers, legal counsel and we analyze each
claim for potential exposure and estimate the ultimate liability of each claim. Amounts accrued and
receivable from insurance companies, above the applicable deductible limits, are reflected in Other
Current Assets in the consolidated balance sheet. Such amounts were $3.6 million and $6.1 million
as of December 31, 2006 and 2005, respectively. See related accrued liabilities at Note 7
Detail of Certain Accounts. We have not incurred any significant losses as a result of claims
denied by our insurance carriers. 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 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.
Litigation and Claims
We are involved in various legal proceedings, primarily involving claims for personal injury
under the General Maritime Laws of the United States and the Jones Act as a result of alleged
negligence. In addition, we from time to time incur other claims, such as contract disputes, in the
normal course of business. In that regard, in 1998, one of our subsidiaries, Cal Dive Offshore Ltd
(CDO), entered into a subcontract with Seacore Marine Contractors Limited (Seacore) to provide
a vessel to Seacore for Seacores use in performing a contract with Coflexip Stena Offshore
Newfoundland (Coflexip) in Canada. Due to various difficulties, that contract was terminated and
an arbitration to recover damages was commenced. We were not a party to that arbitration. A
liability finding was made by the arbitrator against Seacore and in favor of Coflexip. Seacore and
Coflexip settled this matter with Seacore paying Coflexip CAD$6.95 million. Seacore then initiated
an arbitration proceeding against CDO seeking payment of that amount, and subsequently commenced a
lawsuit against us seeking the same recovery. Recently we have settled this litigation and
arbitration with us making a payment to Seacore in the amount of CAD$825,000 (or approximately
$703,000) and the parties fully and finally releasing each other from all claims pertaining to the
matter.
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 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 leases affected by this dispute are
the Gunnison leases. On May 2, 2006, the MMS issued an order that superseded and replaced 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 MMS orders. Other operators in the
Deep Water Gulf of Mexico who have received notices similar to ours are seeking royalty relief
under the DWRRA, including Kerr-McGee Oil and Gas Corporation (Kerr-McGee), the operator of
Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the
enforceability of price thresholds in certain deepwater Gulf of Mexico Leases, such as ours. We do
not anticipate that the MMS director will issue decisions in ours or the other companies
administrative appeals until the Kerr-McGee litigation has been resolved. As a result of this
dispute, we have recorded reserves for the disputed royalties (and any other royalties that may be
claimed) plus interest at 5% for our portion of the Gunnison related MMS claim. The total reserved
amount at December 31, 2006 was approximately $42.6 million. At this time, it is not anticipated
that any penalties would be assessed even if we are unsuccessful in its 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.
86
Commitments
We plan to convert the Caesar (acquired in January 2006 for $27.5 million in cash) into a
deepwater pipelay vessel. Total conversion costs are estimated to be approximately $110 million, of
which approximately $15.0 million had been incurred, with an additional $52.2 million committed at
December 31, 2006. In addition, we will upgrade the Q4000 to include drilling via the addition of
a modular-based drilling system for approximately $40 million, of which approximately $15.3 million
had been incurred, with an additional $19.0 million committed at December 31, 2006.
In addition, in September 2006, we announced our plan to commit to the construction of a $160
million multi-service dynamically positioned dive support/ well intervention vessel (Well
Enhancer) that will be capable of working in the North Sea and West of Shetlands to support our
contract extension to provide light well intervention services for Shell UK Ltd. We expect the
Well Enhancer to join our fleet in 2008. At December 31, 2006, we had incurred approximately $19.4
million, with an additional $87.3 million committed to this project.
Further, we, along with Kommandor RØMØ, have begun the conversion of a ferry vessel into a
dynamically-positioned construction services vessel. Conversion of the vessel is expected to be
completed in two phases. The first phase of the conversion is estimated to be approximately $60
million and is expected to be completed by the end of 2007. As of December 31, 2006, $16.8 million
had been incurred related to the conversion (our portion was $8.4 million), with an additional
$14.0 million committed. The second phase of the conversion into a minimal floating production
system, Helix Producer I, is expected to be completed by mid 2008. Estimated cost of conversion
for the second phase is approximately $100 million, in which we expect to fund 100%. See Note
9 Consolidated Variable Interest Entities for a detailed discussion of Kommandor.
As of December 31, 2006, we have also committed approximately $138.9 million in additional
capital expenditures for exploration, development and drilling costs related to our oil and gas
properties.
Note 18 Business Segment Information
Our operations are conducted through the following lines of businesses: contracting services
operations and oil and gas operations. We have disaggregated our contracting services operations
into three reportable segments in accordance with SFAS 131: Contracting Services, Shelf Contracting
and Production Facilities. As a result, our reportable segments consist of the following:
Contracting Services (formerly known as Deepwater Contracting), Shelf Contracting, Oil and Gas
(formerly known as Oil and Gas Production) and Production Facilities. Contracting Services
operations include deepwater pipelay, well operations, robotics and reservoir and well tech
services. Shelf Contracting operations consist of assets deployed primarily for diving-related
activities and shallow water construction. See Note 3 for discussion of initial public
offering of CDI common stock (represented by the Shelf Contracting segment). All material
Intercompany transactions between the segments have been eliminated.
We evaluate our performance based on income before income taxes of each segment. Segment
assets are comprised of all assets attributable to the reportable segment. The majority of our
Production Facilities segment (Deepwater Gateway and Independence Hub) are accounted for under the
equity method of accounting. Our investment in Kommandor was consolidated in accordance with FIN
46 and is included in our Production Facilities segment.
87
The following summarizes certain financial data by business segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
485,246 |
|
|
$ |
328,315 |
|
|
$ |
197,688 |
|
Shelf Contracting |
|
|
509,917 |
|
|
|
223,211 |
|
|
|
126,546 |
|
Oil and Gas |
|
|
429,607 |
|
|
|
275,813 |
|
|
|
243,310 |
|
Intercompany elimination |
|
|
(57,846 |
) |
|
|
(27,867 |
) |
|
|
(24,152 |
) |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,366,924 |
|
|
$ |
799,472 |
|
|
$ |
543,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
90,454 |
|
|
$ |
42,333 |
|
|
$ |
(8,825 |
) |
Shelf Contracting(1)(2) |
|
|
184,879 |
|
|
|
60,078 |
|
|
|
14,692 |
|
Oil and Gas |
|
|
132,104 |
|
|
|
123,104 |
|
|
|
117,682 |
|
Production Facilities(3) |
|
|
(1,051 |
) |
|
|
(977 |
) |
|
|
(345 |
) |
Intercompany elimination |
|
|
(8,024 |
) |
|
|
|
|
|
|
(173 |
) |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
398,362 |
|
|
$ |
224,538 |
|
|
$ |
123,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense and other |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services(5) |
|
$ |
36,076 |
|
|
$ |
8,571 |
|
|
$ |
4,663 |
|
Shelf Contracting |
|
|
(163 |
) |
|
|
(45 |
) |
|
|
|
|
Oil and Gas |
|
|
(1,339 |
) |
|
|
(1,117 |
) |
|
|
602 |
|
Production Facilities |
|
|
60 |
|
|
|
150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
34,634 |
|
|
$ |
7,559 |
|
|
$ |
5,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of production facilities investments |
|
$ |
18,413 |
|
|
$ |
10,608 |
|
|
$ |
7,927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services(4) |
|
$ |
277,512 |
|
|
$ |
33,762 |
|
|
$ |
(13,488 |
) |
Shelf Contracting(1)(2) |
|
|
185,042 |
|
|
|
60,123 |
|
|
|
14,692 |
|
Oil and Gas |
|
|
133,443 |
|
|
|
124,221 |
|
|
|
117,080 |
|
Production Facilities(3) |
|
|
17,302 |
|
|
|
9,481 |
|
|
|
7,582 |
|
Intercompany elimination |
|
|
(8,024 |
) |
|
|
|
|
|
|
(173 |
) |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
605,275 |
|
|
$ |
227,587 |
|
|
$ |
125,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
140,306 |
|
|
$ |
9,949 |
|
|
$ |
(7,574 |
) |
Shelf Contracting |
|
|
65,710 |
|
|
|
21,009 |
|
|
|
5,166 |
|
Oil and Gas |
|
|
45,084 |
|
|
|
40,734 |
|
|
|
42,787 |
|
Production Facilities |
|
|
6,056 |
|
|
|
3,327 |
|
|
|
2,655 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
257,156 |
|
|
$ |
75,019 |
|
|
$ |
43,034 |
|
|
|
|
|
|
|
|
|
|
|
88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Identifiable assets |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
1,313,206 |
|
|
$ |
736,852 |
|
|
$ |
597,257 |
|
Shelf Contracting |
|
|
452,153 |
|
|
|
277,446 |
|
|
|
145,226 |
|
Oil and Gas |
|
|
2,282,715 |
|
|
|
478,522 |
|
|
|
229,083 |
|
Production Facilities |
|
|
242,113 |
|
|
|
168,044 |
|
|
|
67,192 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
4,290,187 |
|
|
$ |
1,660,864 |
|
|
$ |
1,038,758 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
130,938 |
|
|
$ |
90,037 |
|
|
$ |
21,016 |
|
Shelf Contracting |
|
|
38,086 |
|
|
|
32,383 |
|
|
|
1,792 |
|
Oil and Gas |
|
|
282,318 |
|
|
|
238,698 |
|
|
|
27,315 |
|
Production Facilities |
|
|
45,327 |
|
|
|
111,429 |
|
|
|
32,206 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
496,669 |
|
|
$ |
472,547 |
|
|
$ |
82,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Contracting Services |
|
$ |
34,165 |
|
|
$ |
25,102 |
|
|
$ |
20,227 |
|
Shelf Contracting(1) |
|
|
24,515 |
|
|
|
15,734 |
|
|
|
19,032 |
|
Oil and Gas |
|
|
134,967 |
|
|
|
70,637 |
|
|
|
69,046 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
193,647 |
|
|
$ |
111,473 |
|
|
$ |
108,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included pre-tax $790,000 and $3.9 million of asset impairment charges in 2005 and
2004, respectively. |
|
(2) |
|
Included $(487,000) and $2.8 million equity in (losses) earnings from investment in
OTSL in 2006 and 2005, respectively. |
|
(3) |
|
Represents selling and administrative expense of Production Facilities incurred by us.
See Equity in Earnings of Production Facilities investments for earnings contribution. |
|
(4) |
|
Includes pre-tax gain of $223.1 million related to the initial public offering of CDI
common stock and transfer of debt through dividend distributions from CDI. |
|
(5) |
|
Includes interest expense related to the Term Loan. The Proceeds from the Tem Loan
were used to fund the cash portion of the Remington acquisition. |
89
Intercompany segment revenues during the years ended December 31, 2006, 2005 and 2004
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Contracting Services |
|
$ |
42,585 |
|
|
$ |
26,431 |
|
|
$ |
22,246 |
|
Shelf Contracting |
|
|
15,261 |
|
|
|
1,436 |
|
|
|
1,906 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
57,846 |
|
|
$ |
27,867 |
|
|
$ |
24,152 |
|
|
|
|
|
|
|
|
|
|
|
Intercompany segment profit (which only relates to intercompany capital projects) during
the years ended December 31, 2006, 2005 and 2004 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Contracting Services |
|
$ |
2,460 |
|
|
$ |
|
|
|
$ |
91 |
|
Shelf Contracting |
|
|
5,564 |
|
|
|
|
|
|
|
82 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8,024 |
|
|
$ |
|
|
|
$ |
173 |
|
|
|
|
|
|
|
|
|
|
|
During the years ended December 31, 2006, 2005 and 2004, we derived approximately $190.1
million, $83.2 million and $77.1 million, respectively, of our revenues from the U.K. sector
utilizing approximately $238.5 million, $168.4 million and $136.7 million, respectively, of our
total assets in this region. The majority of the remaining revenues were generated in the U.S.
Gulf of Mexico.
Note 19 Allowance for Uncollectible Accounts
The following table sets forth the activity in our Allowance for Uncollectible Accounts for
each of the three years in the period ended December 31, 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Beginning balance |
|
$ |
585 |
|
|
$ |
7,768 |
|
|
$ |
7,462 |
|
Additions |
|
|
3,598 |
|
|
|
2,577 |
|
|
|
2,745 |
|
Deductions |
|
|
(3,201 |
) |
|
|
(9,760 |
) |
|
|
(2,439 |
) |
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
982 |
|
|
$ |
585 |
|
|
$ |
7,768 |
|
|
|
|
|
|
|
|
|
|
|
See Note 2Summary of Significant Accounting Policies for a detailed discussion
regarding our accounting policy on Accounts Receivable and Allowance for Uncollectible Accounts.
Note 20 Supplemental Oil and Gas Disclosures (Unaudited)
The following information regarding our oil and gas producing activities is presented pursuant
to SFAS No. 69, Disclosures About Oil and Gas Producing Activities (in thousands).
90
Capitalized Costs
Aggregate amounts of capitalized costs relating to our oil and gas activities and the
aggregate amount of related accumulated depletion, depreciation and amortization as of the dates
indicated are presented below:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Unproved oil and gas properties |
|
$ |
101,845 |
|
|
$ |
|
|
Proved oil and gas properties |
|
|
1,576,742 |
|
|
|
475,583 |
|
|
|
|
|
|
|
|
Total oil and gas properties |
|
|
1,678,587 |
|
|
|
475,583 |
|
|
|
|
|
|
|
|
|
|
Accumulated depletion, depreciation and amortization |
|
|
(335,112 |
) |
|
|
(160,651 |
) |
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
1,343,475 |
|
|
$ |
314,932 |
|
|
|
|
|
|
|
|
Included in capitalized costs of proved oil and gas properties being amortized is an
estimate of our proportionate share of decommissioning liabilities assumed relating to these
properties which are also reflected as decommissioning liabilities in the accompanying consolidated
balance sheets at fair value on a discounted basis. At December 31, 2006 and 2005, our oil and gas
operations decommissioning liabilities were $167.7 million and $121.4 million, respectively.
Costs Incurred in Oil and Gas Producing Activities
The following table reflects the costs incurred in oil and gas property acquisition and
development activities, including estimated decommissioning liabilities assumed, during the years
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United |
|
|
United |
|
|
|
|
|
|
States |
|
|
Kingdom |
|
|
Total |
|
Year Ended December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
770,307 |
|
|
$ |
365 |
|
|
$ |
770,672 |
|
Unproved properties |
|
|
105,519 |
|
|
|
|
|
|
|
105,519 |
|
|
|
|
|
|
|
|
|
|
|
Total property acquisition costs |
|
|
875,826 |
|
|
|
365 |
|
|
|
876,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs |
|
|
143,459 |
|
|
|
|
|
|
|
143,459 |
|
Development costs(1) |
|
|
159,688 |
|
|
|
|
|
|
|
159,688 |
|
Asset retirement cost |
|
|
32,863 |
|
|
|
7,579 |
|
|
|
40,442 |
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
1,211,836 |
|
|
$ |
7,944 |
|
|
$ |
1,219,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
183,837 |
|
|
$ |
|
|
|
$ |
183,837 |
|
Unproved properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property acquisition costs |
|
|
183,837 |
|
|
|
|
|
|
|
183,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs |
|
|
5,728 |
|
|
|
|
|
|
|
5,728 |
|
Development costs(1) |
|
|
67,193 |
|
|
|
|
|
|
|
67,193 |
|
Asset retirement cost |
|
|
36,119 |
|
|
|
|
|
|
|
36,119 |
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
292,877 |
|
|
$ |
|
|
|
$ |
292,877 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Unproved properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property acquisition costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs |
|
|
|
|
|
|
|
|
|
|
|
|
Development costs(1) |
|
|
38,171 |
|
|
|
|
|
|
|
38,171 |
|
Asset retirement cost |
|
|
202 |
|
|
|
|
|
|
|
202 |
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
38,373 |
|
|
$ |
|
|
|
$ |
38,373 |
|
|
|
|
|
|
|
|
|
|
|
91
|
|
|
(1) |
|
Development costs include costs incurred to obtain access to proved reserves to drill
and equip development wells. Development costs also include costs of developmental dry
holes. |
Results of Operations for Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United |
|
|
United |
|
|
|
|
|
|
States |
|
|
Kingdom |
|
|
Total |
|
Year Ended December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
429,607 |
|
|
$ |
|
|
|
$ |
429,607 |
|
Production (lifting) costs |
|
|
89,139 |
|
|
|
|
|
|
|
89,139 |
|
Exploration expenses(2) |
|
|
43,115 |
|
|
|
|
|
|
|
43,115 |
|
Depreciation, depletion, amortization and accretion |
|
|
134,967 |
|
|
|
|
|
|
|
134,967 |
|
Gain on sale of oil and gas properties |
|
|
2,248 |
|
|
|
|
|
|
|
2,248 |
|
Selling and administrative |
|
|
27,645 |
|
|
|
4,885 |
|
|
|
32,530 |
|
|
|
|
|
|
|
|
|
|
|
Pretax income (loss) from producing activities |
|
|
136,989 |
|
|
|
(4,885 |
) |
|
|
132,104 |
|
Income tax expense (benefit) |
|
|
47,527 |
|
|
|
(2,443 |
) |
|
|
45,084 |
|
|
|
|
|
|
|
|
|
|
|
Results of oil and gas producing activities(1) |
|
$ |
89,462 |
|
|
$ |
(2,442 |
) |
|
$ |
87,020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
275,813 |
|
|
$ |
|
|
|
$ |
275,813 |
|
Production (lifting) costs |
|
|
56,235 |
|
|
|
|
|
|
|
56,235 |
|
Exploration expenses(2) |
|
|
6,465 |
|
|
|
|
|
|
|
6,465 |
|
Depreciation, depletion, amortization and accretion |
|
|
70,637 |
|
|
|
|
|
|
|
70,637 |
|
Selling and administrative |
|
|
19,372 |
|
|
|
|
|
|
|
19,372 |
|
|
|
|
|
|
|
|
|
|
|
Pretax income from producing activities |
|
|
123,104 |
|
|
|
|
|
|
|
123,104 |
|
Income tax expense |
|
|
40,734 |
|
|
|
|
|
|
|
40,734 |
|
|
|
|
|
|
|
|
|
|
|
Results of oil and gas producing activities(1) |
|
$ |
82,370 |
|
|
$ |
|
|
|
$ |
82,370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
243,310 |
|
|
$ |
|
|
|
$ |
243,310 |
|
Production (lifting) costs |
|
|
39,410 |
|
|
|
|
|
|
|
39,410 |
|
Depreciation, depletion, amortization and accretion |
|
|
69,046 |
|
|
|
|
|
|
|
69,046 |
|
Selling and administrative |
|
|
17,789 |
|
|
|
|
|
|
|
17,789 |
|
|
|
|
|
|
|
|
|
|
|
Pretax income from producing activities |
|
|
117,065 |
|
|
|
|
|
|
|
117,065 |
|
Income tax expense |
|
|
42,787 |
|
|
|
|
|
|
|
42,787 |
|
|
|
|
|
|
|
|
|
|
|
Results of oil and gas producing activities(1) |
|
$ |
74,278 |
|
|
$ |
|
|
|
$ |
74,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes net interest expense and other. |
|
(2) |
|
See Note 5 for additional information related to the components of our exploration
costs. |
Estimated Quantities of Proved Oil and Gas Reserves
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 (140 fields as of December 31, 2006). 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) 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
92
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 performed 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 the producing properties together with a
percentage of the 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 83% of the total
discounted future net revenues. Huddleston audited approximately 81% of our total reserve base in
the United States, including what was deemed to be the most valuable properties. Huddleston
audited 76% of proved developed reserves and 85% of the proved undeveloped reserves totaling 81% of
both categories combined. Huddleston also analyzed the methods utilized by us in the preparation of
all of the estimated reserves and revenues. Huddlestons audit report represents they believe our
methodologies are consistent with the methodologies required by the SEC, SPE and FASB. There were
no limitations imposed, nor limitations encountered by us or Huddleston.
93
The following table presents our net ownership interest in proved oil reserves (MBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United |
|
United |
|
|
|
|
States |
|
Kingdom |
|
Total |
Total proved reserves at December 31, 2003 |
|
|
12,521 |
|
|
|
|
|
|
|
12,521 |
|
Revision of previous estimates |
|
|
(1,412 |
) |
|
|
|
|
|
|
(1,412 |
) |
Production |
|
|
(2,593 |
) |
|
|
|
|
|
|
(2,593 |
) |
Purchases of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
Sales of reserves in place |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
Extensions and discoveries |
|
|
2,002 |
|
|
|
|
|
|
|
2,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves at December 31, 2004 |
|
|
10,517 |
|
|
|
|
|
|
|
10,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous estimates |
|
|
(403 |
) |
|
|
|
|
|
|
(403 |
) |
Production |
|
|
(2,473 |
) |
|
|
|
|
|
|
(2,473 |
) |
Purchases of reserves in place |
|
|
6,653 |
|
|
|
|
|
|
|
6,653 |
|
Sales of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries |
|
|
579 |
|
|
|
|
|
|
|
579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves at December 31, 2005 |
|
|
14,873 |
|
|
|
|
|
|
|
14,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|