UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark
One)
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R
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the fiscal year ended December 31, 2009
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or
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£
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) of the Securities Exchange Act
of 1934
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For the transition period
from
to
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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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95-3409686
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(State
or other jurisdiction
of
incorporation or organization)
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(I.R.S.
Employer
Identification
No.)
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400
North Sam Houston Parkway East Suite 400
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77060
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Houston,
Texas
(Address
of principal executive offices)
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(Zip
Code)
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(281) 618-0400
(Registrant’s
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
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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. R Yes £ No
Indicate by check
mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. £ Yes R 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. R Yes £ No
Indicate by check
mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted
and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the registrant
was required to submit and post such files). £ Yes £ No
Indicate by check mark if disclosure
of delinquent filers pursuant to Item 405 of Regulation S-K
(§ 229.405 of this chapter) is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. £
Indicate by check
mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated filer” and “smaller reporting company”
in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated
filer R
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Accelerated filer £
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Non-accelerated
filer £
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Smaller reporting company£
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(Do not check
if a smaller reporting company)
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Indicate by check
mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). £ Yes R No
The aggregate
market value of the voting and non-voting common equity held by non-affiliates
of the registrant based on the last reported sales price of the Registrant’s
Common Stock on June 30, 2009 was approximately $1.0 billion.
The number of
shares of the registrant’s Common Stock outstanding as of February 19, 2010
was 104,691,894.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the
definitive Proxy Statement for the Annual Meeting of Shareholders to be held on
May 12, 2010, are incorporated by reference into Part III
hereof.
HELIX
ENERGY SOLUTIONS GROUP, INC. INDEX — FORM 10-K
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Page
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PART I
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Item 1A.
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18 | |
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Item 1B.
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27 | |
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Item
2.
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Item
3.
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Item
4.
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Unnumbered
Item
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PART II
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Item
5.
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Item
6.
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Item
7.
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Item
7A.
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Item
8.
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| 74 | ||
| Report of Independent Registered Public Accounting Firm on Internal Control Over | 75 | |
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Item 9.
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Item 9A.
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Item 9B.
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| PART III | ||
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Item
10.
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Item
11.
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Item
12.
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Item
13.
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Item
14.
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| PART IV | ||
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Item
15.
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Forward
Looking Statements
This Annual Report
on Form 10-K (“Annual Report”) contains various statements that contain
forward-looking information regarding Helix Energy Solutions Group, Inc. and
represent our expectations and beliefs concerning future
events. This forward looking information is intended to be
covered by the safe harbor for “forward-looking statements” provided by the
Private Securities Litigation Reform Act of 1995 as set forth in
Section 27A of the Securities Act of 1933, as amended, and Section 21E
of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All
statements, included herein or incorporated herein by reference, that are
predictive in nature, that depend upon or refer to future events or conditions,
or that use terms and phrases such as “achieve,” “anticipate,” “believe,”
“estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,”
“predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,”
“should,” “could” and similar terms and phrases are forward-looking statements.
Included in forward-looking statements are, among other
things:
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statements
regarding our business strategy, including the potential sale of assets
and/or other investments in our subsidiaries and facilities, or any other
business plans, forecasts or objectives, any or all of which is subject to
change;
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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 oil and gas property or well;
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statements
related to commodity prices for oil and gas or with respect to the supply
of and demand for oil and gas;
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statements
relating to our proposed acquisition, exploration, development and/or
production of oil and gas properties, prospects or other interests and any
anticipated costs related thereto;
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statements
related to environmental risks, exploration and development risks, or
drilling and operating risks;
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statements
relating to the construction or acquisition of vessels or equipment 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, working capital or other financial items;
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statements
regarding any financing transactions or arrangements, or ability to enter
into such transactions;
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statements
regarding any Securities and Exchange Commission (“SEC”) 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;
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statements
regarding general economic or political conditions, whether international,
national or in the regional and local market areas in which we do
business;
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statements
related to our ability to retain key members of our senior management and
key employees;
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statements
related to the underlying assumptions related to any projection or
forward-looking statement; and
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any other
statements that relate to non-historical or future
information.
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Although we believe
that the expectations reflected in these forward-looking statements are
reasonable and are based on reasonable assumptions, they do involve risks,
uncertainties and other factors that could cause actual results to be materially
different from those in the forward-looking statements. These factors
include, among other things:
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impact of the
weak economic conditions and the future impact of such conditions on the
oil and gas industry and the demand for our services;
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uncertainties
inherent in the development and production of oil and gas and in
estimating reserves;
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the
geographic concentration of our oil and gas operations;
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uncertainties
regarding our ability to replace depletion;
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unexpected
capital expenditures (including the amount and nature
thereof);
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impact of oil
and gas price fluctuations and the cyclical nature of the oil and gas
industry;
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the effects
of indebtedness, which could adversely restrict our ability to operate,
could make us vulnerable to general adverse economic and industry
conditions, could place us at a competitive disadvantage compared to our
competitors that have less debt and could have other adverse consequences
to us;
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the
effectiveness of our derivative activities;
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the results
of our continuing efforts to control or reduce costs and improve
performance;
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the success
of our risk management activities;
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the effects
of competition;
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the
availability (or lack thereof) of capital (including any financing) to
fund our business strategy and/or operations and the terms of any such
financing;
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the impact of
current and future laws and governmental regulations, including tax and
accounting developments;
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the effect of
adverse weather conditions and/or other risks associated with marine
operations;
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the effect of
environmental liabilities that are not covered by an effective indemnity
or insurance;
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the potential
impact of a loss of one or more key employees; and
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the impact of
general, market, industry or business
conditions.
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Our actual results
could differ materially from those anticipated in any forward-looking statements
as a result of a variety of factors, including those discussed in “Risk Factors”
beginning on page 18 of this Annual Report. All forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by these risk factors. Forward-looking statements are only as of
the date they are made, and other than as required under the securities laws, we
assume no obligation to update or revise these forward-looking statements or
provide reasons why actual results may differ.
PART I
Item 1. Business
OVERVIEW
Helix Energy
Solutions Group, Inc. (“Helix”) is an international offshore energy company,
incorporated in the state of Minnesota in 1979, that provides field development
solutions and other contracting services to the energy market as well as to our
own oil and gas properties. Our Contracting Services segment utilizes our
vessels, offshore equipment and methodologies to deliver services that may
reduce finding and development (“F&D”) costs and encompass the complete
lifecycle of an offshore oil and gas field. Our Oil and Gas segment engages in
prospect generation, exploration, development and production activities. Our
primary operations are located in the Gulf of Mexico, North Sea, Asia Pacific
and West Africa regions. Unless the context indicates otherwise, as used in this
Annual Report, the terms “Company,” “we,” “us” and “our” refer collectively to
Helix and its subsidiaries. Until June 2009, Cal Dive
International, Inc. (collectively with its subsidiaries referred to as
“Cal Dive” or “CDI”) was a majority-owned subsidiary of
Helix. Helix sold substantially all its remaining ownership interests
in Cal Dive during 2009 (see “Contracting Services Operations – Shelf
Contracting” below).
In
December 2008, we announced the intention to focus and shape the future of the
Company around our deepwater construction and well intervention
services. For additional information regarding this strategy
announcement and about our deepwater construction and well intervention services
see sections titled “The Industry and Our Strategy,” “Contracting
Services” and “Contracting Services Operations” all included elsewhere within
Item 1. “Business” of this Annual Report.
Our principal
executive offices are located at 400 North Sam Houston Parkway East,
Suite 400, Houston, Texas 77060; phone number 281-618-0400. Our common
stock trades on the New York Stock Exchange (“NYSE”) under the ticker symbol
“HLX”. Our Chief Executive Officer submitted the annual CEO
certification to the NYSE as required under its listed Company Manual in April
2009. Our principal executive officer and our principal financial officer have
made the certifications required under Section 302 of the Sarbanes-Oxley
Act, which are included as exhibits to this report.
Please refer to the
subsection “— Certain Definitions” on page 8 for definitions of
additional terms commonly used in this Annual Report.
CONTRACTING
SERVICES
We
seek to provide services and methodologies which we believe are critical to
finding and developing offshore reservoirs and maximizing production
economics. Our “life of field” services are organized in three
disciplines: subsea construction, well operations and production facilities. We
have disaggregated our contracting services operations into three reportable
segments: Contracting Services (which includes subsea construction, well
operations and drilling); Shelf Contracting, which we ceased reporting as a
business segment in June 2009 (see “Contracting Services Operations – Shelf
Contracting” below); and Production Facilities.
Subsea
Construction
For over 30 years,
we have supported offshore oil and natural gas infrastructure projects by
providing our services, which include the construction and maintenance of
pipelines, production platforms, risers and subsea production systems primarily
in the Gulf of Mexico, North Sea, Asia Pacific, West Africa and Middle East
regions. Our subsea construction services include pipelay and robotics in water
depths exceeding 1,000 feet. We also provide construction services
periodically from our well intervention vessels. Historically we
performed traditional subsea services, including air and saturation diving,
salvage work and shallow water pipelay on the Outer Continental Shelf (“OCS”) of
the Gulf of Mexico in water depths up to 1,000 feet through Cal Dive,
a majority-owned subsidiary until June 2009, at which time we sold a substantial
amount of our remaining ownership interest in Cal Dive reducing ownership of Cal
Dive to approximately 26%. In September 2009 we sold substantially all our
remaining ownership interest in Cal Dive. The financial results
of Cal Dive are consolidated in our accompanying financial statements
through June 10, 2009 and are recorded under the equity method from June 10,
2009 until September 23, 2009 (see Item 8. Financial
Statements and Supplementary Data” — Note 3 — “Ownership
of Cal Dive International Inc.”).
Well
Operations
We
engineer, manage and conduct well construction, intervention, drilling and
decommissioning operations in water depths ranging primarily from approximately
200 feet to 10,000 feet. Over the long term, we expect an increased demand
for these services caused by the growing number of subsea tree installations,
coupled with our lower cost solutions as compared to an offshore rig.
Accordingly, we constructed a newbuild vessel (the “Well
Enhancer”) that joined our fleet in October 2009 and is performing work
in the North Sea. We also expanded geographically in Australia
and Asia in 2007 with the acquisition of Seatrac Pty Ltd. (“Seatrac”), an
established Australian well operations company now named Well Ops SEA Pty
Limited (“WOSEA”).
Production
Facilities
We
own interests in certain production facilities in hub locations where there is
potential for significant subsea tieback activity. Ownership of production
facilities enables us to earn a transmission company type return through tariff
charges while providing construction work for our vessels. We own a 50% interest
in the Marco Polo tension leg platform (“TLP”), which is located in
4,300 feet of water in the Gulf of Mexico, through Deepwater Gateway,
L.L.C. (“Deepwater Gateway”). Enterprise Products Partners L.P. owns the
remaining 50% of Deepwater Gateway. We also own a 20% interest in
Independence Hub, LLC (“Independence Hub”), an affiliate of Enterprise Products
Partners L.P. Independence Hub owns a 105-foot deep draft, semi-submersible
platform, which was installed during 2007. The Independence Hub platform is
located in a water depth of 8,000 feet and serves as a regional hub for up
to one billion cubic feet of natural gas production per day from multiple
ultra-deepwater fields in the eastern Gulf of Mexico. Finally, through an
approximate 81% owned consolidated entity, we are nearing completion of the
conversion of a vessel into a ship shaped dynamically-positioned floating
production unit capable of processing up to 45,000 barrels of oil and
70 MMcf of natural gas per day, which we intend to initially use to handle the
future oil and gas production from our Phoenix field in the deepwater of the
Gulf of Mexico (see Item 2. Properties – Significant Oil and Gas
Properties).
Our contracting
services has consisted of three of our business segments: Contracting Services,
Shelf Contracting (until June 2009) and Production
Facilities. We ceased reporting the results of our former Shelf
Contracting segment in June 2009 when Cal Dive was deconsolidated from our
financial statements following the reduction of our ownership of Cal Dive to
below 50%. Our fourth business segment is Oil and Gas (see
below). Significant financial information relating to our operations
by segments and by geographic areas for the last three years is contained in
Item 8. Financial
Statements
and Supplementary Data “— Note 18 — Business Segment
Information.”
OIL
AND GAS
We
formed our oil and gas operations in 1992 to develop and provide more efficient
solutions for the abandonment requirements of companies operating offshore, to
expand the asset utilization of our contracting services assets and to achieve
incremental returns. We have evolved this business model to include
not only mature oil and gas properties but also proved and unproved reserves yet
to be developed and explored. In July 2006, we acquired Remington Oil and Gas
Corporation (“Remington”), an exploration, development and production company
with operations located primarily in the Gulf of Mexico. As of
December 31, 2009, we had approximately 578 Bcfe of estimated proved reserves
with approximately 98% associated with properties located in the Gulf of Mexico.
As discussed in “The Industry and Our Strategy” below, in December 2008, we
announced that we intend to seek the potential sale of part or all of our oil
and gas operations; however, until any potential disposition occurs, we believe
that owning interests in reservoirs, particularly in deepwater, provides the
following:
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a potential
backlog for our service assets as a hedge against cyclical service asset
utilization;
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potential
utilization for new non-conventional applications of service assets to
hedge against lack of initial market acceptance and utilization risk;
and
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incremental
returns.
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Our oil and gas
operations include an experienced team of personnel providing expertise in
geology, geophysics, reservoir engineering, drilling, production engineering,
facilities management, lease operations and petroleum land management. We seek
to maximize returns on our oil and gas investments by lowering F&D costs,
reducing development time, operating our fields more effectively, and extending
the reservoir life through well exploitation operations. Our reservoir
engineering and geophysical expertise, along with our access to contracting
services assets that may positively impact a project’s development costs, have
enabled us to partner with many other oil and gas companies in offshore
development projects.
THE
INDUSTRY AND OUR STRATEGY
In
December 2008, we announced our intention to focus and shape the future
direction of the Company around our deepwater construction and well intervention
services that comprise our Contracting Services business. We intend
to achieve this strategic focus by seeking and evaluating strategic
opportunities to sell certain non-core assets, such as:
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all or
a portion of our oil and gas
assets;
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our
ownership interests in one or more of our production facilities;
and
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our
remaining interest in CDI.
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We also
announced that economic and financial market conditions may affect the timing of
any strategic dispositions by us and, therefore, a degree of patience would be
required in order to execute any transactions. We continue to
focus on reducing debt levels through monetization of non-core assets and
allocation of free cash flow in order to accelerate our strategic
goals.
Since the
announcement of our strategy to monetize certain of our non-core business
assets, we have:
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Sold five oil
and gas properties for approximately $68 million in gross
proceeds;
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Sold a total
of 15.2 million shares of CDI common stock held by us to CDI for $100
million in separate transactions in January and June 2009 (Note
3);
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Sold Helix
RDS Limited, our subsurface reservoir consulting business for $25 million
in April 2009; and
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Sold a total
of 45.8 million shares of CDI common stock held by us to third parties in
two separate public secondary offerings for approximately $404.4 million,
net of underwriting fees in June 2009 and September
2009.
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Demand for our
contracting services operations is primarily influenced by the condition of the
oil and gas industry and, in particular, the willingness of oil and gas
companies to make capital expenditures for offshore exploration, drilling and
production operations. Generally, spending for our contracting
services fluctuates directly with the direction of oil and natural gas prices.
The performance of our oil and gas operations is also largely dependent on the
prevailing market prices for oil and natural gas, which are impacted by global
economic conditions, hydrocarbon production and excess capacity, geopolitical
issues, weather and several other factors.
Global economic
conditions deteriorated significantly in 2008 with declines in the oil and
natural gas market accelerating during the fourth quarter of
2008. Although we currently are experiencing a weak economic
environment, we believe that the long-term industry fundamentals are positive
based on the following factors: (1) long term increasing world demand for oil
and natural gas; (2) peaking global production rates;
(3) globalization of the natural gas market; (4) increasing number of
mature and small reservoirs; (5) increasing ratio of contribution to global
production from marginal fields; (6) increasing offshore activity,
particularly in deepwater; and (7) increasing number of subsea
developments. Our current strategy of combining Contracting Services Operations
and Oil and Gas operations allows us to focus on trends (4) through
(7) in that we pursue long-term sustainable growth by applying specialized
subsea services to the broad external offshore market but with a complementary
focus on fields and new reservoirs in which we have an equity
stake.
Our primary goal is
to provide services and methodologies to the industry which we believe are
critical to finding and developing offshore reservoirs and maximizing the
economics from marginal fields. A secondary goal is for our oil and gas
operations to generate prospects and find and develop oil and gas employing our
key services and methodologies resulting in a reduction in F&D costs.
Meeting these objectives drives our ability to achieve our primary goal of
maximizing the value for our shareholders. In order to achieve these goals we
will:
Continue
Expansion of Contracting Services Capabilities. We will focus
on providing offshore services that deliver the highest financial return to us.
We may make strategic investments in capital projects that expand our service
capabilities or add capacity to existing services in our key operating regions.
Our capital investments have included adding deepwater drilling capability to
our Q4000
vessel, converting a vessel into a dynamically positioned floating
production unit (Helix
Producer
I), converting a former dynamically positioned cable lay vessel into a
deepwater pipelay vessel (the Caesar),
and we completed the construction of a newbuild vessel (Well
Enhancer) that provides
us with greater well servicing capabilities. The Well
Enhancer is currently working in the North Sea
region.
Monetize
Oil and Gas Reserves and Non-Core Assets. We intend to sell
down interests in oil and gas reserves once value has been created via prospect
generation, discovery and/or development engineering. Through this approach we
seek to lower reservoir and commodity risk, lower capital expenditures and
increase contracting services profits. We may sell interests in oil
and gas reserves at any time during the life of the
properties.
As
stated previously, we will focus on services which are critical to lowering
F&D costs, particularly on fields in the deepwater. In connection with this
strategy, in December 2006, we sold a minority stake (26.5%) in our Shelf
Contracting business through a carve-out initial public offering. Our interest
in CDI was further reduced through CDI’s acquisition of Horizon Offshore, Inc.
(“Horizon”) in December 2007 and was 57.2% at December 31, 2008. In
January 2009, CDI acquired 13.6 million shares of its outstanding common shares
from us, reducing our ownership in CDI to approximately 51%. We subsequently
sold additional shares of CDI stock held by us in two separate public secondary
offerings in June 2009 and September 2009, respectively. We
currently own less than 1% of CDI. See Item 8. Financial
Statements
and Supplementary Data “— Note 3 — Ownership of Cal Dive
International, Inc.”
Generate
Prospects and Focus Exploration Drilling on Select Deepwater Prospects. Our
oil and gas operations continue to function normally following our December 2008
announcement that all or a portion of such properties may be
sold. This means we will continue to generate prospects
and drill in areas we believe are likely to contain oil and natural gas reserves
and where our contracting services assets can be utilized and incremental
returns will be achieved through control of and application of our development
services and methodologies. To minimize our F&D costs, we may utilize the
Q4000
for some of our deepwater drilling needs once regulatory approval has
been obtained. Additionally, we plan to seek partners on these prospects to
mitigate risk associated with the cost of drilling and development
work.
Continue
Exploitation Activities and Converting PUD/PDNP Reserves into Production. Over
the years, our oil and gas operations have been able to achieve incremental
operating returns and increased operating cash flow due in part to our ability
to convert proved undeveloped reserves (“PUD”) and proved developed
non-producing reserves (“PDNP”) into producing assets through successful
exploitation drilling and well work. As of December 31, 2009, the PUD
category for our U.S. Gulf of Mexico properties
totaled approximately 352 Bcfe or 62% of our total domestic
estimated proved reserves. All of our U.K proved reserves
totaling approximately 12 Bcfe are considered to be PUD at December 31,
2009. We will focus on cost effectively developing these reserves to
generate oil and gas production, or alternatively, selling full or partial
interests in them to fund our core service business and/or retire outstanding
debt.
Certain
Definitions
Defined below are
certain terms helpful to understanding our business:
Bcfe: One
billion cubic feet equivalent, with one barrel of oil being equivalent to six
thousand cubic feet of natural gas.
Deepwater: Water
depths exceeding 1,000 feet.
Dive
Support Vessel (DSV): Specially equipped vessel that performs
services and acts as an operational base for divers, remotely operated vehicles
(“ROV”) and specialized equipment.
Dynamic
Positioning (DP): Computer directed thruster systems that use
satellite based positioning and other positioning technologies to ensure the
proper counteraction to wind, current and wave forces enabling the vessel to
maintain its position without the use of anchors.
DP-2: Two
DP systems on a single vessel pursuant to which the redundancy allows the vessel
to maintain position even with the failure of one DP system, required for
vessels which support both manned diving and robotics and for those working in
close proximity to platforms. DP-2 are necessary to provide the redundancy
required to support safe deployment of divers, while only a single DP system is
necessary to support ROV operations.
E&P: Oil
and gas exploration and production activities.
F&D: Total
cost of finding and developing oil and gas reserves.
G&G: Geological
and geophysical.
IRM: Inspection,
repair and maintenance.
Life
of Field Services: Services performed on offshore facilities,
trees and pipelines from the beginning to the end of the economic life of an oil
field, including installation, inspection, maintenance, repair, well
intervention and abandonment.
MBbl: When
describing oil or other natural gas liquid, refers to 1,000 barrels with
each barrel containing 42 gallons.
Minerals
Management Service (MMS): The federal regulatory body for the
United States having responsibility for the mineral resources of the United
States OCS.
Mcf: When
describing natural gas, refers to 1 thousand cubic feet.
MMcf: When
describing natural gas, refers to 1 million cubic feet.
Moonpool: An
opening in the center of a vessel through which a saturation diving system or
ROV may be deployed, allowing safe deployment in adverse weather
conditions.
MSV: Multipurpose
support vessel.
Outer
Continental Shelf (OCS): For purposes of our industry, areas
in the Gulf of Mexico from the shore to 1,000 feet of water
depth.
Peer
Group-Contracting Services: For purposes of this Annual Report
on Form 10-K, FMC Technologies, Inc. (NYSE: FTI), Global Industries, Ltd.
(NASDAQ: GLBL), McDermott International, Inc. (NYSE: MDR), Oceaneering
International, Inc. (NYSE: OII), Cameron International Corporation (NYSE: CAM),
Pride International, Inc. (NYSE: PDE), Oil States International, Inc. (NYSE:
OIS), Rowan Companies, Inc. (NYSE: RDC), and Tidewater Inc. (NYSE:
TDW).
Peer
Group-Oil and Gas: For purposes of this Annual Report on Form
10-K, ATP Oil & Gas Corporation (NASDAQ: ATPG), W&T Offshore, Inc.
(NYSE: WTI), and Mariner Energy, Inc. (NYSE: ME).
Proved
Developed Non-Producing (PDNP): Proved developed oil and gas
reserves that are expected to be recovered from (1) completion intervals
which are open at the time of the estimate but which have not started producing,
or (2) wells that require additional completion work or future recompletion
prior to the start of production.
Proved
Developed Shut-In (PDSI): Proved developed oil and gas
reserves associated with wells that exhibited calendar year production, but were
not online January 1, 2009.
Proved
Developed Reserves (PDP): Reserves that geological and
engineering data indicate with reasonable certainty to be recoverable today, or
in the near future, with current technology and under current economic
conditions.
Proved
Undeveloped Reserves (PUD): Proved undeveloped oil and gas
reserves that are expected to be recovered from a new well on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion.
QHSE: Quality,
Health, Safety and Environmental programs to protect the environment,
safeguard employee health and eliminate injuries.
Remotely
Operated Vehicle (ROV): Robotic vehicles used to complement,
support and increase the efficiency of diving and subsea operations and for
tasks beyond the capability of manned diving operations.
ROVDrill: ROV
deployed coring system developed to take advantage of existing ROV technology.
The coring package, deployed with the ROV system, is capable of taking cores
from the seafloor in water depths up to 3,000m. Because the system operates from
the seafloor there is no need for surface drilling strings and the larger
support spreads required for conventional coring.
Saturation
Diving: Saturation diving, required for work in water depths
between 200 and 1,000 feet, involves divers working from special chambers
for extended periods at a pressure equivalent to the pressure at the work
site.
Spar: Floating
production facility anchored to the sea bed with catenary mooring
lines.
Spot
Market: Prevalent market for subsea contracting in the Gulf of
Mexico, characterized by projects that are generally short in duration and often
on a turnkey basis. These projects often require constant rescheduling and the
availability or interchangeability of multiple vessels.
Stranded
Field: Smaller PUD reservoir that standing alone may not
justify the economics of a host production facility and/or infrastructure
connections.
Subsea
Construction Vessels: Subsea services are typically performed
with the use of specialized construction vessels which provide an above-water
platform that functions as an operational base for divers and ROVs.
Distinguishing characteristics of subsea construction vessels include DP
systems, saturation diving capabilities, deck space, deck load, craneage and
moonpool launching. Deck space, deck load and craneage are important features of
a vessel’s ability to transport and fabricate hardware, supplies and equipment
necessary to complete subsea projects.
Tension
Leg Platform (TLP): A floating production facility anchored to
the seabed with tendons.
Trencher
or Trencher System: A subsea robotics system capable of
providing post lay trenching, inspection and burial (PLIB) and maintenance of
submarine cables and flowlines in water depths of 30 to 7,200 feet across a
range of seabed and environmental conditions.
Ultra-Deepwater: Water
depths beyond 4,000 feet.
Working
Interest: The interest in an oil and natural gas property
(normally a leasehold interest) that gives the owner the right to drill, produce
and conduct operations on the property and to a share of production, subject to
all royalties, overriding royalties and other burdens and to all costs of
exploration, development and operations and all risks in connection
therewith.
CONTRACTING
SERVICES OPERATIONS
We
provide a full range of contracting services primarily in the Gulf of Mexico,
North Sea, Asia Pacific and West Africa regions primarily
in deepwater. Our services include:
|
|
•
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Development. Installation
of subsea pipelines, flowlines, control umbilicals, manifold assemblies,
risers; pipelay and burial; installation and tie-in of riser and manifold
assembly; commissioning, testing and inspection; and cable and umbilical
lay and connection;
|
|
|
•
|
Production. Inspection,
repair and maintenance (IRM) of production structures, risers, pipelines
and subsea equipment; well intervention; life of field support; and
intervention
engineering; and
|
|
|
•
|
Decommissioning. Decommissioning
and remediation services; plugging and abandonment services; platform
salvage and removal services; pipeline abandonment services; and site
inspections.
|
We
provide offshore services and methodologies that we believe are critical to
finding and developing offshore reservoirs and maximizing production
economics. These “life of field” services are represented by three
disciplines: (1) construction, (2) well operations and (3) production
facilities. As of December 31, 2009, our contracting services
operations’ backlog supported by written agreements or contracts
totaled $251.0 million, of which $216.7 million is expected to
be completed in 2010. These backlog contracts are cancellable without
penalty in many cases. Backlog is not a reliable indicator of total
annual revenue for our Contracting Services businesses as contracts may be
added, cancelled and in many cases modified while in progress.
Subsea
Construction
Construction
services which we believe are critical to the development of fields in the
deepwater include the use of umbilical lay and pipelay vessels and
ROVs. We currently own three subsea umbilical lay and pipelay
vessels. The Intrepid
is a 381-foot DP-2 vessel capable of laying rigid and flexible pipe
(up to 8 inches in diameter) and umbilicals. The Express
is a 502-foot DP-2 vessel also capable of laying rigid and flexible pipe
(up to 14 inches in diameter) and umbilicals. In January 2006, we acquired
the Caesar,
a mono-hull built in 2002 for the cable lay market. The Caesar
is 485 feet long and has a state-of-the-art DP-2 system. In
January 2010, the Caesar
arrived in the Gulf of Mexico after its conversion into a subsea pipelay
asset capable of laying rigid pipe up to 36 inches in
diameter. The Caesar
will undergo additional capital improvements in the United States before
being placed in service in our fleet, which is expected to occur in the first
half of 2010. Our total investment in the Caesar
is expected to range between $290 million and $300 million (including
capitalized interest of approximately $24 million) when it is
completed. We also periodically provide construction services from
our well intervention vessels, Seawell,
Q4000
and the newly completed Well
Enhancer, which was placed in service in October 2009.
We
operate ROVs, trenchers and ROVDrills designed for offshore
construction. As marine construction support in the Gulf of Mexico
and other areas of the world moves to deeper waters, use of ROV systems is
increasing and the scope of their services is more significant. Our vessels add
value by supporting deployment of our ROVs. We provide our customers with vessel
availability and schedule flexibility to meet the technological challenges of
these subsea construction developments in the Gulf of Mexico and
internationally. Our 39 ROVs and five trencher systems operate in three regions:
the Americas, Europe/West Africa and Asia Pacific.
The results of our
Subsea division are reported under our Contracting Services segment. See
Item 8. Financial
Statements and Supplementary Data “— Note 18 — Business Segment
Information.”
Shelf
Contracting
Our former Shelf
Contracting segment represented the operations and results of CDI while CDI was
a consolidated, majority-owned subsidiary of Helix. We
deconsolidated CDI on June 10, 2009 when our ownership interest in CDI decreased
below 50% (see Item 8. Financial
Statement and Supplementary Data “— Note 3 — Ownership of
Cal Dive International, Inc.”). Shelf Contracting services provided
by CDI included manned diving services, pipelay and pipebury services, platform
installation and salvage service. Shelf Contracting also performed
saturation, surface and mixed gas diving which enabled us to provide a full
complement of manned diving services in water depths of up to
1,000 feet.
See Item 8.
Financial
Statements and Supplementary Data “— Note 18 — Business
Segment Information.”
For the results of
our former Shelf Contracting services segment.
Well
Operations
We
engineer, manage and conduct well construction, intervention, drilling and
decommissioning operations in water depths ranging from 200 to 10,000 feet.
The increased number of subsea wells installed and the periodic shortfall in
both rig availability and equipment have resulted in an increased demand for
Well Operations services in the regions in which we operate.
As major and
independent oil and gas companies expand operations in the deepwater basins of
the world, development of these reserves will often require the installation of
subsea trees. Historically, drilling rigs were typically necessary for subsea
well operations to troubleshoot or enhance production, shift sleeves, log wells
or perform recompletions. Three of our vessels serve as work platforms for well
operations services at costs significantly less than drilling rigs. In the Gulf
of Mexico, our multi-service semi-submersible vessel, the Q4000, has set a series
of well operations “firsts” in increasingly deeper water without the use of a
traditional drilling rig. In the North Sea, the Seawell
has
provided intervention and abandonment services for over 700 North Sea subsea
wells since 1987. Competitive advantages of our vessels are derived from their
lower operating costs, together with an ability to mobilize quickly and to
maximize production time by performing a broad range of tasks related to
intervention, construction, inspection, repair and maintenance. These services
provide a cost advantage in the development and management of subsea reservoir
developments. With the expected long-term increased demand for these services
due to the growing number of subsea tree installations, we have the potential
for significant backlog for both these working assets and, as a result, we
constructed a newbuild vessel, the Well
Enhancer. The Well
Enhancer joined our
fleet in October 2009 in the North Sea region. Additional limited
capital expenditures remain to be incurred to upgrade certain capabilities of
the Well
Enhancer. We
have incurred total costs of $233 million on the Well
Enhancer through
December 31, 2009 and its total cost is expected to be between $250 million and
$260 million (including capitalized interest of approximately $16 million) when
the remaining capital upgrades are completed. Our operations expanded
within Australia and Asia following the acquisition of a well established
Australian well operations company in 2006. In February 2010,
we announced the formation of a joint venture with Australian-based engineering
and construction company Clough Limited, to provide a range of subsea services
to offshore operators in the Asia Pacific region. Services provided by the joint
venture, named Clough Helix Pty Ltd, will include subsea well intervention and
well abandonment, SURF (subsea infrastructure, umbilical, riser and flowline
installation), saturation and air diving and subsea inspection, repair and
maintenance services.
The results of Well
Operations are reported under our Contracting Services segment. See Item 8.
Financial
Statements and Supplementary Data “— Note 18 — Business
Segment Information.”
Production
Facilities
We
own interests in certain production facilities in hub locations where there is
potential for significant subsea tieback activity. There are a significant
number of small discoveries that cannot justify the economics of a dedicated
host facility. These discoveries are typically developed as subsea tie backs to
existing facilities when capacity through the facility is available.
11
We have
historically invested in over-sized facilities that allow operators of these
fields to tie back without burdening the operator of the hub reservoir. We are
positioned to facilitate the tie back of certain of these smaller reservoirs to
these hubs through our services. Ownership of production facilities enables us
to earn a transmission company type return through tariff charges while
periodically providing construction work for our vessels. We own a 50% interest
in Deepwater Gateway which owns the Marco Polo TLP, is located in
4,300 feet of water in the Gulf of Mexico. We also own a 20% interest in
Independence Hub which owns the Independence Hub platform, a 105-foot deep
draft, semi-submersible platform located in a water depth of 8,000 feet
that serves as a regional hub for up to one billion cubic feet of natural
gas production per day from multiple ultra-deepwater fields in the previously
untapped eastern Gulf of Mexico.
When a hub is not
feasible, we intend to apply an integrated application of our services in a
manner that cumulatively lowers development costs to a point that allows for a
small dedicated facility to be used. This strategy will permit the development
of some fields that otherwise would be non-commercial to develop. The commercial
risk is mitigated because we have a portfolio of reservoirs and the assets to
redeploy the facility. For example, through an approximate 81% owned and
consolidated entity, we are nearing completion of conversion of a
vessel (the Helix Producer
I) into a ship-shaped dynamically positioned floating production unit
capable of processing up to 45,000 barrels of oil and 70 MMcf of natural gas per
day. We intend this unit to first be utilized on the Phoenix field,
which we acquired in 2006 after the hurricanes of 2005 destroyed the TLP which
was being used to produce the field. We believe the
Helix Producer I will be ready to process first production from the
Phoenix field around mid-year 2010. Once production in the Phoenix
area ceases, this re-deployable facility is expected to be moved to a new
location, contracted to a third party, or used to produce other internally-owned
reservoirs.
The results of
production facilities services are reported under our Production Facilities
segment. See Item 8. Financial
Statements and Supplementary Data “— Note 18 — Business
Segment Information.”
OIL &
GAS OPERATIONS
We
formed our oil and gas operations in 1992 to develop and provide more efficient
solutions for offshore abandonment requirements, to expand the utilization of
our contracting services assets and to achieve incremental
returns. We have evolved this business model to include not only
mature oil and gas properties but also proved and unproved reserves yet to be
developed and explored. In July 2006, we acquired Remington Oil and Gas
Corporation (“Remington”), an exploration, development and production company
with operations located primarily in the Gulf of Mexico. This
acquisition led to the assembly of services that allows us to create value at
key points in the life of a reservoir from exploration through development, life
of field management and operating through abandonment. As of December 31,
2009, our estimated proved reserves totaled approximately 578 Bcfe with
approximately 98% of such reserves associated with properties located in the
Gulf of Mexico.
As
announced in December 2008, we are seeking to monetize the value of our oil and
gas assets through the disposition of all or a portion of our oil and gas
operations. Although this is our intention, until such time as an
acceptable offer is made for our properties, we will continue to build on their
value by operating them consistent with our past practices. We
cannot provide assurances that the sale of all or any portion of our oil and gas
operations will be completed or that we will be able to negotiate an acceptable
price or acceptable terms. Also, all material dispositions of assets
and/or investments in our non-core businesses require obtaining approval from
our Board of Directors. We believe that owning interests in oil and gas
reservoirs, particularly in the Deepwater, provides the following:
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•
|
a potential
backlog for our service assets as a hedge against cyclical service asset
utilization;
|
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•
|
potential
utilization for new non-conventional applications of service assets to
hedge against lack of initial market acceptance and utilization risk;
and
|
||
|
•
|
incremental
returns.
|
Our oil and gas
operations are currently involved in all stages of a reservoir’s life. This
complete life-cycle involvement allows us to meaningfully improve the economics
of a reservoir that would otherwise be considered non-commercial or non-impact
and has identified us as a value adding partner to many producers. Our
expertise, along with similarly aligned interests, allows us to develop more
efficient relationships with other producers. With a historical focus on
acquiring non-impact reservoirs or mature fields, we have been successful in
acquiring equity interests in several Deepwater undeveloped reservoirs. In the
event we continue to own and operate our oil and gas assets, developing these
fields over the next few years will require significant capital commitments by
us and/or others and may provide significant backlog for our construction
assets.
Our oil and gas
operations have a significant prospect inventory, mostly in the Deepwater, which
we believe will generate significant life of field services for our vessels. To
minimize F&D costs, we may utilize the Q4000
for some of our Deepwater future drilling needs. Our Oil and Gas segment
has a proven track record of developing prospects into production in the U.S.
Gulf of Mexico. We plan to seek partners on these prospects to
mitigate risk associated with the costs of drilling and
development.
We
identify prospective oil and gas properties primarily by using 3-D seismic
technology. After acquiring an interest in a prospective property, our strategy
is to partner with others to drill one or more exploratory wells. If the
exploratory well(s) find commercial oil and/or gas reserves, we complete the
well(s) and install the necessary infrastructure to begin producing the oil
and/or gas. Because our operations are located offshore Gulf of Mexico, we must
install facilities such as offshore platforms and gathering pipelines in order
to produce the oil and gas and deliver it to the marketplace. Certain properties
require additional drilling to fully develop the oil and gas reserves and
maximize the production from a particular discovery.
Our oil and gas
operations include an experienced team of personnel providing services in
geology, geophysics, reservoir engineering, drilling, production engineering,
facilities management, lease operations and petroleum land management. We seek
to maximize profitability by lowering F&D costs, lowering development time
and cost, operating the field more effectively, and extending the reservoir life
through well exploitation operations. When a company sells an OCS property, it
retains the financial responsibility for plugging and decommissioning if its
purchaser becomes financially unable to do so. Thus, it becomes important that a
property be sold to a purchaser that has the financial wherewithal to perform
its contractual obligations. We believe we have a strong reputation among major
and independent oil companies. In addition, our reservoir engineering and
geophysical expertise, along with our access to contracting service assets that
can positively impact development costs, have enabled us to partner with many
other oil and gas companies in offshore development projects. We share ownership
in our oil and gas properties with various industry participants. We currently
operate the majority of our offshore properties. An operator is generally able
to maintain a greater degree of control over the timing and amount of capital
expenditures than a non-operating interest owner. See Item 2. Properties
“— Summary of Natural Gas and Oil Reserve Data” for detailed
disclosures of our oil and gas properties.
The results of our
oil and gas operations are reported under our Oil and Gas segment. See
Item 8. Financial
Statements and Supplementary Data “— Note 18 — Business
Segment Information.”
GEOGRAPHIC
AREAS
Revenue by
geographic region during is as follows (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
United States
|
$
|
923,481
|
$
|
1,394,108
|
$
|
1,261,844
|
||||||
|
United Kingdom
|
124,896
|
160,186
|
205,529
|
|||||||||
|
India
|
233,466
|
214,288
|
36,433
|
|||||||||
|
Other
|
179,844
|
345,492
|
228,614
|
|||||||||
|
Total
|
$
|
1,461,687
|
$
|
2,114,074
|
$
|
1,732,420
|
||||||
We
include the property and equipment, net of accumulated depreciation, in the
geographic region in which it is legally owned. The following table
provides our property and equipment, net of depreciation, by geographic region
(in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
United States
|
$
|
2,564,673
|
$
|
3,170,866
|
$
|
3,014,283
|
||||||
|
United Kingdom
|
284,637
|
206,009
|
187,551
|
|||||||||
|
Other
|
14,396
|
41,568
|
41,073
|
|||||||||
|
Total
|
$
|
2,863,706
|
$
|
3,418,443
|
$
|
3,242,907
|
||||||
CUSTOMERS
Our customers
include major and independent oil and gas producers and suppliers, pipeline
transmission companies and offshore engineering and construction firms. The
level of construction services required by any particular contracting customer
depends on the size of that customer’s capital expenditure budget devoted to
construction plans in a particular year. Consequently, customers that account
for a significant portion of contract revenues in one fiscal year may represent
an immaterial portion of contract revenues in subsequent fiscal years. The
percent of consolidated revenue of major customers, those whose total
represented 10% or more of our consolidated revenues, was as follows: 2009—Shell
Offshore, Inc. (12%); 2008 — Louis Dreyfus Energy Services (10%) and Shell
Offshore, Inc. (12%); and 2007 — Louis Dreyfus Energy Services (14%) and
Shell Offshore, Inc. (10%). These customers were purchasers of our oil and gas
production. We estimate that in 2009 we provided subsea services to over 200
customers.
Our contracting
services projects have historically been of short duration and are generally
awarded shortly before mobilization. As a result, no significant backlog existed
prior to 2007. Beginning in 2007, we entered into several long-term contracts
for certain of our Deepwater and Well Operations vessels. In addition, our
production portfolio inherently provides a backlog of work for our services that
we can complete at our option based on market conditions. As of
December 31, 2009, our contracting services operations’ backlog supported
by written agreements or contracts totaled $251.0 million, of which
$216.7 million is expected to be completed in 2010. These
backlog contracts are cancellable without penalty in many
cases. Backlog is not a reliable indicator of total annual revenue
for our Contracting Services businesses as contracts may be added, cancelled and
in many cases modified while in progress.
COMPETITION
The contracting
services industry is highly competitive. While price is a factor, the ability to
acquire specialized vessels, attract and retain skilled personnel, and
demonstrate a good safety record are also important. Our competitors on the OCS
include Global Industries, Ltd., Oceaneering International, Inc. and a number of
smaller companies, some of which only operate a single vessel and often compete
solely on price. For Deepwater projects, our principal competitors include
Acergy S.A., Allseas Group S.A., Subsea 7 Inc. and Technip. Our
competitors in the well intervention business are the international drilling
contractors and specialized contractors.
Our oil and gas
operations compete with large integrated oil and gas companies as well as
independent exploration and production companies for offshore leases on
properties. We also encounter significant competition for the acquisition of
mature oil and gas properties. Our ability to acquire additional properties
depends upon our ability to evaluate and select suitable properties and
consummate transactions in a historically highly competitive environment. Many
of our competitors may have significantly more financial, personnel,
technological, and other resources available to them. In addition, some of the
larger integrated companies may be better able to respond to industry changes
including price fluctuation, oil and gas demands, and governmental regulations.
Small or mid-sized producers, and in some cases financial players, with a focus
on acquisition of proved developed and undeveloped reserves, are often
competition on development properties.
TRAINING,
SAFETY AND QUALITY ASSURANCE
We
have established a corporate culture in which QHSE remains among the highest of
priorities. Our corporate goal, based on the belief that all accidents can be
prevented, is to provide an incident-free workplace by focusing on correct and
safe behavior. Our QHSE procedures, training programs and management system were
developed by management personnel, common industry work practices and by
employees with on-site experience who understand the physical challenges of the
ocean work site. As a result, management believes that our QHSE programs are
among the best in the industry. We have introduced a company-wide effort to
enhance and provide continuous improvements to our behavioral based safety
process, as well as our training programs, that continue to focus on safety
through open communication. The process includes the documentation of all daily
observations, collection of data and data treatment to provide the mechanism of
understanding both safe and unsafe behaviors at the worksite. In addition, we
initiated scheduled Hazard Hunts by project management on each vessel, complete
with assigned responsibilities and action due dates. Our Contracting
Services business has ISO accreditation such as ISO 9001 (Quality Management
Systems) and ISO 14001 (Environmental Management System).
GOVERNMENT
REGULATION
Many aspects of the
offshore marine construction industry are subject to extensive governmental
regulations. We are subject to the jurisdiction of the U.S. Coast Guard
(“USCG”), the U.S. Environmental Protection Agency, the MMS and the
U.S. Customs Service, as well as private industry organizations such as the
American Bureau of Shipping (“ABS”). In the North Sea, international regulations
govern working hours and a specified working environment, as well as standards
for diving procedures, equipment and diver health. These North Sea standards are
some of the most stringent worldwide. In the absence of any specific regulation,
our North Sea operations adhere to standards set by the International Marine
Contractors Association and the International Maritime Organization. In
addition, we operate in other foreign jurisdictions that have various types of
governmental laws and regulations to which we are subject.
The Coast Guard
sets safety standards and is authorized to investigate vessel and diving
accidents and to recommend improved safety standards. The Coast Guard also is
authorized to inspect vessels at will. We are required by various governmental
and quasi-governmental agencies to obtain various permits, licenses and
certificates with respect to our operations. We believe that we have obtained or
can obtain all permits, licenses and certificates necessary for the conduct of
our business.
In
addition, we depend on the demand for our services from the oil and gas
industry, and therefore, our business is affected by laws and regulations, as
well as changing tax laws and policies, relating to the oil and gas industry
generally. In particular, the development and operation of oil and gas
properties located on the OCS of the United States is regulated primarily by the
MMS.
The MMS requires
lessees of OCS properties to post bonds or provide other adequate financial
assurance in connection with the plugging and abandonment of wells located
offshore and the removal of all production facilities. Operators on the OCS are
currently required to post an area-wide bond of $3.0 million, or $0.5
million per producing lease. We have provided adequate financial assurance for
our offshore leases as required by the MMS.
We
acquire production rights to offshore mature oil and gas properties under
federal oil and gas leases, which the MMS administers. These leases contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
(“OCSLA”). These MMS directives are subject to change. The MMS has promulgated
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specifications. The MMS also has issued
regulations restricting the flaring or venting of natural gas and prohibiting
the burning of liquid hydrocarbons without prior authorization. Similarly, the
MMS has promulgated other regulations governing the plugging and abandonment of
wells located offshore and the removal of all production facilities. Finally,
under certain circumstances, the MMS may require any operations on federal
leases to be suspended or terminated or may expel unsafe operators from existing
OCS platforms and bar them from obtaining future leases. Suspension or
termination of our operations or expulsion from operating on our leases and
obtaining future leases could have a material adverse effect on our financial
condition and results of operations.
Under the OCSLA and
the Federal Oil and Gas Royalty Management Act, MMS also administers oil and gas
leases and establishes regulations that set the basis for royalties on oil and
gas. The regulations address the proper way to value production for royalty
purposes, including the deductibility of certain post-production costs from that
value. Separate sets of regulations govern natural gas and oil and are subject
to periodic revision by MMS.
Historically, the
transportation and sale for resale of natural gas in interstate commerce has
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (“NGPA”), and the regulations promulgated thereunder by the Federal
Energy Regulatory Commission (“FERC”). In the past, the federal government has
regulated the prices at which oil and gas could be sold. While sales by
producers of natural gas, and all sales of crude oil, condensate and natural gas
liquids currently can be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead sales in the
natural gas industry began with the enactment of the NGPA. In 1989, the Natural
Gas Wellhead Decontrol Act was enacted, removing both price and non-price
controls from natural gas sold in “first sales” no later than January 1,
1993.
Sales of natural
gas are affected by the availability, terms and cost of transportation. The
price and terms for access to pipeline transportation remain subject to
extensive federal and state regulation. Several major regulatory changes have
been implemented by Congress and FERC since 1985 that affect the economics of
natural gas production, transportation and sales. In addition, as a result of
the Energy Policy Act of 2005, FERC continues to promulgate revisions to various
aspects of the rules and regulations affecting those segments of the natural gas
industry, most notably interstate natural gas transmission companies, that
remain subject to FERC jurisdiction. In addition, however, changes in FERC rules
and regulations may also affect the intrastate transportation of natural gas, as
well as the sale of natural gas in interstate and intrastate commerce, under
certain circumstances. The stated purpose of many of these regulatory changes is
to promote competition among the various sectors of the natural gas industry,
and to prevent fraud and manipulation of interstate transportation markets. We
cannot predict what further action FERC will take on these matters, but we do
not believe any such action will materially adversely affect us differently from
other companies with which we compete.
Additional
proposals and proceedings before various federal and state regulatory agencies
and the courts could affect the oil and gas industry. We cannot predict when or
whether any such proposals may become effective. In the past, the natural gas
industry has been heavily regulated. There is no assurance that the regulatory
approach currently pursued by FERC will continue indefinitely. Notwithstanding
the foregoing, we do not anticipate that compliance with existing federal, state
and local laws, rules and regulations will have a material effect upon our
capital expenditures, financial conditions, earnings or competitive
position.
ENVIRONMENTAL
REGULATION
Our operations are
subject to a variety of national (including federal, state and local) and
international laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Numerous
governmental departments issue rules and regulations to implement and enforce
such laws that are often complex and costly to comply with and that carry
substantial administrative, civil and possibly criminal penalties for failure to
comply. Under these laws and regulations, we may be liable for remediation or
removal costs, damages and other costs associated with releases of hazardous
materials (including oil) into the environment, and such liability may be
imposed on us even if the acts that resulted in the releases were in compliance
with all applicable laws at the time such acts were performed. Some of the
environmental laws and regulations that are applicable to our business
operations are discussed in the following paragraphs, but the discussion does
not cover all environmental laws and regulations that govern our
operations.
The Oil Pollution
Act of 1990, as amended (“OPA”), imposes a variety of requirements on
“Responsible Parties” related to the prevention of oil spills and liability for
damages resulting from such spills in waters of the United States. A
“Responsible Party” includes the owner or operator of an onshore facility, a
vessel or a pipeline, and the lessee or permittee of the area in which an
offshore facility is located. OPA imposes liability on each Responsible Party
for oil spill removal costs and for other public and private damages from oil
spills. Failure to comply with OPA may result in the assessment of civil and
criminal penalties. OPA establishes liability limits of $350 million for
onshore facilities, all removal costs plus $75 million for offshore
facilities, and the greater of $854,400 or $1,000 per gross ton for vessels
other than tank vessels. The liability limits are not applicable, however, if
the spill is caused by gross negligence or willful misconduct; if the spill
results from violation of a federal safety, construction, or operating
regulation; or if a party fails to report a spill or fails to cooperate fully in
the cleanup. Few defenses exist to the liability imposed under OPA. Management
is currently unaware of any oil spills for which we have been designated as a
Responsible Party under OPA that will have a material adverse impact on us or
our operations.
OPA also imposes
ongoing requirements on a Responsible Party, including preparation of an oil
spill contingency plan and maintaining proof of financial responsibility to
cover a majority of the costs in a potential spill. We believe that we have
appropriate spill contingency plans in place. With respect to financial
responsibility, OPA requires the Responsible Party for certain offshore
facilities to demonstrate financial responsibility of not less than
$35 million, with the financial responsibility requirement potentially
increasing up to $150 million if the risk posed by the quantity or quality
of oil that is explored for or produced indicates that a greater amount is
required. The MMS has promulgated regulations implementing these financial
responsibility requirements for covered offshore facilities. Under the MMS
regulations, the amount of financial responsibility required for an offshore
facility is increased above the minimum amounts if the “worst case” oil spill
volume calculated for the facility exceeds certain limits established in the
regulations. We believe that we currently have established adequate proof of
financial responsibility for our onshore and offshore facilities and that we
satisfy the MMS requirements for financial responsibility under OPA and
applicable regulations.
In
addition, OPA requires owners and operators of vessels over 300 gross tons
to provide the Coast Guard with evidence of financial responsibility to cover
the cost of cleaning up oil spills from such vessels. We currently own and
operate seven vessels over 300 gross tons. We have provided
satisfactory evidence of financial responsibility to the Coast Guard for all of
our vessels.
The Clean Water Act
imposes strict controls on the discharge of pollutants into the navigable waters
of the United States and imposes potential liability for the costs of
remediating releases of petroleum and other substances. The controls and
restrictions imposed under the Clean Water Act have become more stringent over
time, and it is possible that additional restrictions will be imposed in the
future. Permits must be obtained to discharge pollutants into state and federal
waters. Certain state regulations and the general permits issued under the
Federal National Pollutant Discharge Elimination System Program prohibit the
discharge of produced waters and sand, drilling fluids, drill cuttings and
certain other substances related to the exploration for, and production of, oil
and gas into certain coastal and offshore waters. The Clean Water Act provides
for civil, criminal and administrative penalties for any unauthorized discharge
of oil and other hazardous substances and imposes liability on responsible
parties for the costs of cleaning up any environmental contamination caused by
the release of a hazardous substance and for natural resource damages resulting
from the release. Many states have laws that are analogous to the Clean Water
Act and also require remediation of releases of petroleum and other hazardous
substances in state waters. Our vessels routinely transport diesel fuel to
offshore rigs and platforms and also carry diesel fuel for their own use. Our
vessels transport bulk chemical materials used in drilling activities and also
transport liquid mud which contains oil and oil by-products. Offshore facilities
and vessels operated by us have facility and vessel response plans to deal with
potential spills. We believe that our operations comply in all material respects
with the requirements of the Clean Water Act and state statutes enacted to
control water pollution.
OCSLA provides the
federal government with broad discretion in regulating the production of
offshore resources of oil and gas, including authority to impose safety and
environmental protection requirements applicable to lessees and permittees
operating in the OCS. Specific design and operational standards may apply to OCS
vessels, rigs, platforms, vehicles and structures. Violations of lease
conditions or regulations issued pursuant to OCSLA can result in substantial
civil and criminal penalties, as well as potential court injunctions curtailing
operations and cancellation of leases. Because our operations rely on offshore
oil and gas exploration and production, if the government were to exercise its
authority under OCSLA to restrict the availability of offshore oil and gas
leases, such action could have a material adverse effect on our financial
condition and results of operations. As of this date, we believe we are not the
subject of any civil or criminal enforcement actions under OCSLA.
The Comprehensive
Environmental Response, Compensation, and Liability Act (“CERCLA”) contains
provisions requiring the remediation of releases of hazardous substances into
the environment and imposes liability, without regard to fault or the legality
of the original conduct, on certain classes of persons including owners and
operators of contaminated sites where the release occurred and those companies
who transport, dispose of, or arrange for disposal of hazardous substances
released at the sites. Under CERCLA, such persons may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies. Third parties may also file claims for
personal injury and property damage allegedly caused by the release of hazardous
substances. Although we handle hazardous substances in the ordinary course of
business, we are not aware of any hazardous substance contamination for which we
may be liable.
We
operate in foreign jurisdictions that have various types of governmental laws
and regulations relating to the discharge of oil or hazardous substances and the
protection of the environment. Pursuant to these laws and regulations,
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we could
be held liable for remediation of some types of pollution, including the release
of oil, hazardous substances and debris from production, refining or industrial
facilities, as well as other assets we own or operate or which are owned or
operated by either our customers or our sub-contractors.
Management believes
that we are in compliance in all material respects with the applicable
environmental laws and regulations to which we are subject. We do not anticipate
that compliance with existing environmental laws and regulations will have a
material effect upon our capital expenditures, earnings or competitive position.
However, changes in the environmental laws and regulations, or claims for
damages to persons, property, natural resources or the environment, could result
in substantial costs and liabilities, and thus there can be no assurance that we
will not incur significant environmental compliance costs in the
future.
EMPLOYEES
We
rely on the high quality of our workforce. As of January 31, 2010, we had
approximately 1,550 employees, nearly 680 of which were salaried
personnel. As of December 31, 2009, we also contracted with
third parties to utilize 200 non-U.S. citizens to crew our foreign flag
vessels. Except for a very limited number of our workshop employees
in Australia, our employees do not belong to a union nor are they employed
pursuant to any collective bargaining agreement or any similar arrangement. We
believe our relationship with our employees and foreign crew members is
favorable.
WEBSITE
AND OTHER AVAILABLE INFORMATION
We
maintain a website on the Internet with the address of www.HelixESG.com.
Copies of this Annual Report for the year ended December 31, 2009, and
copies of our Quarterly Reports on Form 10-Q for 2009 and 2010 and any
Current Reports on Form 8-K for 2009 and 2010, and any amendments thereto,
are or will be available free of charge at such website as soon as reasonably
practicable after they are filed with, or furnished to, the SEC. In addition,
the Investor Relations portion of our website contains copies of our Code of
Conduct and Business Ethics and our Code of Ethics for Chief Executive Officer
and Senior Financial Officers. We make our website content available for
informational purposes only. Information contained on our website is not part of
this report and should not be relied upon for investment purposes. Please note
that prior to March 6, 2006, the name of the Company was Cal Dive
International, Inc.
The general public may read and copy
any materials we file with the SEC at the SEC’s Public Reference Room at
450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. We are an electronic filer, and the SEC maintains an Internet
website that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the SEC, including
us. The Internet address of the SEC’s website is www.sec.gov.
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 General Corporate Matters
Business
Risks
Our results of
operations could be adversely affected if our business assumptions do not prove
to be accurate or if adverse changes occur in our business environment,
including the following areas:
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general
global economic and business conditions, which affect demand for oil and
natural gas and, in turn, our
business;
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our ability
to manage risks related to our business and
operations;
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our ability
to compete against companies that provide more services and products than
we do, including “integrated service
companies”;
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our ability
to attract and retain skilled, trained personnel to provide technical
services and support for our
business;
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our ability
to procure sufficient supplies of materials essential to our
business in periods of high demand, and to reduce our
commitments for such materials in periods of low
demand;
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consolidation
by our customers, which could result in loss of a customer;
and
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changes in
laws or regulations, including laws relating to the environment or to the
oil and gas industry in general, and other factors, many of which are
beyond our control.
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Economic
downturn and lower oil and natural gas prices could negatively impact our
business.
Our operations are
affected by local, national and worldwide economic conditions and the condition
of the oil and gas industry. Certain economic data indicates the
United States economy and the worldwide economy may require some time to recover
from the recent downturn. The consequences of a prolonged period of
economic decline or little or no economic growth will likely result in a lower
level of economic activity and increased uncertainty regarding the direction of
energy prices and the capital and commodity markets, which will likely
contribute to decreased offshore exploration and drilling. A lower level of
offshore exploration and drilling could have a material adverse effect on the
demand for our services. In addition, a general decline in the level
of economic activity might result in lower commodity prices, which may also
adversely affect our revenues from our oil and gas business and indirectly, our
service business. The extent of the impact of these factors on our results
of operations and cash flow depends on the length and severity of the decreased
demand for our services and lower commodity prices.
Continued market
deterioration could also jeopardize the performance of certain counterparty
obligations, including those of our insurers, customers and financial
institutions. Although we assess the creditworthiness of our
counterparties, prolonged business decline or disruptions as a result of
economic slow down or lower commodity prices could lead to changes in a
counterparty’s liquidity and increase our exposure to credit risk and bad
debts. In the event any such party fails to perform, our financial
results could be adversely affected and we could incur losses and our liquidity
could be negatively impacted.
Lack
of access to the credit market could negatively impact our ability to operate
our business and to execute our business strategy.
Due to the changes
in the global credit market during fiscal 2009, there has been deterioration in
the credit and capital markets and access to financing is limited and uncertain.
If the capital and credit markets continue to experience weakness and the
availability of funds remains limited, we may incur increased costs associated
with any additional financing we may require for future
operations. Because of uncertainty in the market and an inability to
access the capital markets our customers may curtail their capital and operating
expenditure programs, which could result in a decrease in demand for our vessels
and a reduction in fees and/or utilization. In addition, certain of our
customers could experience an inability to pay suppliers, including us, in the
event they are unable to access the capital markets as needed to fund their
business operations. Likewise, our suppliers may be unable to sustain
their current level of operations, fulfill their commitments and/or
fund future operations and obligations, each of which could adversely affect our
operations. Continued lower levels of economic activity and weakness in the
credit markets could also adversely affect our ability to implement our
strategic objectives and dispose of all or any portion of the oil and gas assets
or the production facilities.
In
addition, some financial institutions and insurance companies have reported
significant deterioration in their financial condition during fiscal 2009. Our
forward-looking statements assume that our lenders, insurers and other financial
institutions will be able to fulfill their obligations under our various credit
agreements, insurance policies and contracts. If any of our significant
financial institutions were unable to perform under such agreements, and if we
were unable to find suitable replacements at a reasonable cost, our results of
operations, liquidity and cash flows could be adversely
impacted.
Our
substantial indebtedness and the terms of our indebtedness could impair our
financial condition and our ability to fulfill
our debt obligations.
As
of December 31, 2009, we had approximately $1.4 billion of
consolidated indebtedness outstanding. The significant level of 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 a continued general economic downturn, 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 potential rising interest rates because a portion of our
current and potential future 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 limiting our ability to
use proceeds from asset sales for purposes other than debt repayment
(except in certain circumstances where proceeds may be reinvested under
criteria set forth in our credit
agreements).
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A
continuing period of weak economic activity may make it increasingly difficult
to comply with our covenants and other restrictions in agreements governing our
debt. Our ability to comply with these covenants and other
restrictions is affected by the current economic conditions and other events
beyond our control. If we fail to comply with these covenants and
other restrictions, it could lead to an event of default, the possible
acceleration of our repayment of outstanding debt and the exercise of certain
remedies by the lenders, including foreclosure on our pledged
collateral.
Our
operations outside of the United States subject us to additional
risks.
Our operations
outside of the United States are subject to risks inherent in foreign
operations, including, without limitation:
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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.
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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.
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Pipeline and
processing facilities do not exist in certain areas of exploration and,
therefore, any actual sales of our production could be delayed for extended
periods of time until such facilities are constructed.
We
may not be able to compete successfully against current and future
competitors.
The businesses in
which we operate are highly competitive. Several of our competitors are
substantially larger and have greater financial and other resources than we
have. If other companies relocate or acquire vessels for operations
in the Gulf of Mexico, North Sea, West Africa or Asia Pacific
regions, levels of competition may increase and our business could be adversely
affected. In the exploration and production business, some of the larger
integrated companies may be better able to respond to industry changes including
price fluctuations, oil and gas demand, political change and government
regulations.
In
addition, in a few countries, the national oil companies have formed
subsidiaries to provide oilfield services for them, competing with services
provided by us. To the extent this practice expands, our business could be
adversely impacted.
Government
Regulation, including recent
legislative initiatives, may affect demand for our
services.
Numerous federal
and state regulations affect our operations. Current regulations are constantly
reviewed by the various agencies at the same time that new regulations are being
considered and implemented. In addition, because we hold federal leases, the
federal government requires us to comply with numerous additional regulations
that focus on government contractors. The regulatory burden upon the oil and gas
industry increases the cost of doing business and consequently affects our
profitability. Potential legislation and/or regulatory actions could
increase our costs and reduce our liquidity, delay our operations or otherwise
alter the way we conduct our business. Exploration and development
activities and the production and sale of oil and gas are subject to extensive
federal, state, local and international regulations.
Our operations are
subject to a variety of national (including federal, state and local) and
international laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Numerous domestic
and foreign governmental agencies issue rules and regulations to implement and
enforce such laws that are often complex and costly to comply with and that
carry substantial administrative, civil and possibly criminal penalties for
failure to comply. Under these laws and regulations, we may be liable for
remediation or removal costs, damages and other costs associated with releases
of hazardous materials, including oil into the environment, and such liability
may be imposed on us even if the acts that resulted in the releases were in
compliance with all applicable laws at the time such acts were
performed.
A
variety of regulatory developments, proposals or requirements and legislative
initiatives have been introduced in the domestic and international regions in
which we operate that are focused on restricting the emission of carbon dioxide,
methane and other greenhouse gases.
On
June 26, 2009, the U.S. House of Representatives approved adoption of the
“American Clean Energy and Security Act of 2009,” also known as the
“Waxman-Markey Cap-and-Trade legislation,” or “ACESA.” The purpose of ACESA is
to control and reduce emissions of greenhouse gases in the United States. The
U.S. Senate has begun work on its own legislation for controlling and reducing
emissions of greenhouse gases in the United States. For legislation to become
law, both chambers of U.S. Congress would be required to approve identical
legislation. It is not possible at this time to predict whether or when the
Senate may act on climate change legislation, how any bill approved by the
Senate would be reconciled with ACESA, or how federal legislation may be
reconciled with state and regional requirements.
In
2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that
greenhouse gases are an “air pollutant” under the federal Clean Air Act and thus
subject to future regulation. In December 2009, the U.S.
Environmental Protection Agency (the “EPA”) issued an “endangerment and cause or
contribute finding” for greenhouse gases under the federal Clean Air Act, which
will allow the EPA to draft rules that directly regulate greenhouse gas
emissions.
Recently, the
EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule.
This rule became effective December 29, 2009 and will require the
collection of information beginning in January 2010 with annual reporting to
begin in 2011 for covered facilities. The rule requires reporting of greenhouse
gas emissions from large sources and suppliers in
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the
United States and the EPA has stated that it will use the information to guide
development of the policies and programs to reduce emissions.
These regulatory
developments and legislative initiatives may curtail production and demand for
fossil fuels such as oil and gas in areas of the world where our customers
operate and thus adversely affect future demand for our products and services,
which may in turn adversely affect our future results of
operations. In addition, changes in environmental laws and
regulations, or claims for damages to persons, property, natural resources or
the environment, could result in substantial costs and liabilities, and thus
there can be no assurance that we will not incur significant environmental
compliance costs in the future. Such environmental liability could substantially
reduce our net income and could have a significant impact on our financial
ability to carry out our operations.
In 2009, U.S.
Customs and Border Protection (“CBP”) issued a proposed modification to its
prior rulings regarding the application of the Jones Act to the carriage by
foreign flag vessels of items relating to certain offshore activities on the
OCS. While CBP subsequently withdrew these proposed modifications, we
are aware that the parent agency of CBP, the Department of Homeland Security
(“DHS”), may be preparing a notice of proposed rulemaking respecting the same
subject matter. If DHS proposes a change to the application of the Jones Act
similar to that originally proposed by CBP, and such proposal is adopted, this
development could potentially lead to operational delays or increased operating
costs in instances where we would be required to hire coastwise qualified
vessels that we currently do not own, in order to transport certain merchandise
to projects on the OCS. This could increase our costs of compliance and doing
business and make it more difficult to perform pipelay or well operation
services.
Beginning in 2011,
the federal government has proposed to levy a tax on offshore production and to
repeal a number of existing tax preferences for domestic oil and gas
producers. The tax preferences include, but are not limited, to
the elimination of the immediate expensing of intangible drilling costs, the use
of percentage depletion methodology in respect to oil and gas wells, the ability
to claim the domestic manufacturing deduction against income derived from oil
and gas production and other preference items. The elimination
of one or all of these tax preferences may have an adverse impact on our
financial results in future years. In addition, it is uncertain
as to whether we will be able to recoup these additional tax costs from our
customers.
The
loss of the services of one or more of our key employees, or our failure
to attract
and retain other highly qualified personnel in the future, could disrupt
our operations
and adversely affect our financial results.
Our industry has
lost a significant number of experienced professionals over the years due to,
among other reasons, the volatility in commodity prices. Our continued success
depends on the active participation of our key employees. The loss of our key
people could adversely affect our operations.
In
addition, the delivery of our products and services require personnel with
specialized skills and experience. As a result, our ability to remain productive
and profitable will depend upon our ability to employ and retain skilled
workers. Our ability to expand our operations depends in part on our ability to
increase the size of our skilled labor force. The demand for skilled workers in
our industry is high, and the supply is limited. In addition, although our
employees are not covered by a collective bargaining agreement, the marine
services industry has in the past been targeted by maritime labor unions in an
effort to organize Gulf of Mexico employees. A significant increase in the wages
paid by competing employers or the unionization of our Gulf of Mexico employees
could result in a reduction of our labor force, increases in the wage rates that
we must pay or both. If either of these events were to occur, our capacity and
profitability could be diminished and our growth potential could be
impaired.
If
we fail to effectively manage our growth, our results of operations could
be harmed.
We
have a history of growing through acquisitions of large assets and acquisitions
of companies. We must plan and manage our acquisitions effectively to achieve
revenue growth and maintain profitability in our evolving market. If we fail to
effectively manage current and future acquisitions, our results of operations
could be adversely affected. Our growth has placed significant demands on our
personnel, management and other resources. We must continue to improve our
operational, financial, management and legal compliance information systems to
keep pace with the growth of our business.
Certain
provisions of our corporate documents and Minnesota law may discourage a
third
party from making a takeover proposal.
In
addition to the 6,000 shares of preferred stock held by Fletcher
International, Ltd. pursuant to 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 Articles of
Incorporation give our board of directors the authority, without any action by
our shareholders, to fix the rights and preferences on up to
4,994,000 shares of undesignated preferred stock, including dividend,
liquidation and voting rights. In addition, our by-laws divide the board of
directors into three classes. We are also subject to certain anti-takeover
provisions of the Minnesota Business Corporation Act. We also have employment
arrangements with all of our executive officers that require cash payments in
the event of a “change of control.” Any or all of the provisions or factors
described above may discourage a takeover proposal or tender offer not approved
by management and the board of directors and could result in shareholders who
may wish to participate in such a proposal or tender offer receiving less for
their shares than otherwise might be available in the event of a takeover
attempt.
Risks
Relating to our Contracting Services Operations
Our
contracting services operations are adversely affected by low oil and gas
prices and
by the cyclicality of the oil and gas industry.
Conditions in the
oil and natural gas industry are subject to factors beyond our control. Our
contracting services operations are substantially dependent upon the condition
of the oil and gas industry, and in particular, the willingness of oil and gas
companies to make capital expenditures for offshore exploration, development,
drilling and production operations. The level of capital expenditures generally
depends on the prevailing view of future oil and gas prices, which are
influenced by numerous factors affecting the supply and demand for oil and gas,
including, but not limited to:
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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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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 laws,
regulations and policies.
|
A
sustained period of low drilling and production activity or lower commodity
prices would likely have a material adverse effect on our financial position,
cash flows and results of operations.
The
operation of marine vessels is risky, and we do not have insurance coverage
for all
risks.
Marine construction
involves a high degree of operational risk. Hazards, such as vessels sinking,
grounding, colliding and sustaining damage from severe weather conditions, are
inherent in marine operations. These hazards can cause personal injury or loss
of life, severe damage to and destruction of property and equipment, pollution
or environmental damage, and suspension of operations. Damage arising from such
occurrences may result in lawsuits asserting large claims. Insurance may not be
sufficient or effective under all circumstances or against all hazards to which
we may be subject. A successful claim for which we are not fully insured could
have a material adverse effect on us. Moreover, we cannot assure you that we
will be able to maintain adequate insurance in the future at rates that we
consider reasonable. As a result of market conditions, premiums and deductibles
for certain of our insurance policies have increased substantially and could
escalate further. In some instances, certain insurance could become unavailable
or available only for reduced amounts of coverage. For example, insurance
carriers are now requiring broad exclusions for losses due to war risk and
terrorist acts and limitations for wind storm damages. As construction activity
expands into deeper water in the Gulf of Mexico and other deepwater basins of
the world and with our divestiture of Cal Dive, a greater percentage of our
revenues will be from deepwater construction projects that are larger and more
complex, and thus riskier,
23
than shallow
water projects. As a result, our revenues and profits are increasingly dependent
on our larger vessels. The current insurance on our vessels, in some cases, is
in amounts approximating book value, which could be less than replacement value.
In the event of property loss due to a catastrophic marine disaster, mechanical
failure, collision or other event, insurance may not cover a substantial loss of
revenues, increased costs and other liabilities, and therefore, the loss of any
of our large vessels could have a material adverse effect on
us.
Our
contracting business typically declines in winter, and bad weather in the Gulf
of Mexico or North
Sea can adversely affect our operations.
Marine operations
conducted in the Gulf of Mexico and North Sea are seasonal and depend, in part,
on weather conditions. Historically, we have enjoyed our highest vessel
utilization rates during the summer and fall when weather conditions are
favorable for offshore exploration, development and construction activities. We
typically have experienced our lowest utilization rates in the first quarter. As
is common in the industry, we typically bear the risk of delays caused by some
adverse weather conditions. Accordingly, our results in any one quarter are not
necessarily indicative of annual results or continuing trends.
Certain areas in
and near the Gulf of Mexico and North Sea experience unfavorable weather
conditions including hurricanes and other extreme weather conditions on a
relatively frequent basis. Substantially all of our facilities and assets
offshore and along the Gulf of Mexico and the North Sea, including our vessels
and structures on our offshore oil and gas properties, are susceptible to damage
and/or total loss by these storms. Damage caused by high winds and turbulent
seas could potentially cause us to curtail both service and production
operations for significant periods of time until damage can be assessed and
repaired. Moreover, even if we do not experience direct damage from any of these
storms, we may experience disruptions in our operations because customers may
curtail their development activities due to damage to their platforms, pipelines
and other related facilities.
If
we bid too low on a turnkey contract, we suffer adverse economic
consequences.
A
significant amount of our projects are performed on a qualified turnkey basis
where described work is delivered for a fixed price and extra work, which is
subject to customer approval, is billed separately. The revenue, cost and gross
profit realized on a turnkey contract can vary from the estimated amount because
of changes in offshore job conditions, variations in labor and equipment
productivity from the original estimates, the performance of third parties such
as equipment suppliers, or other factors. These variations and risks inherent in
the marine construction industry may result in our experiencing reduced
profitability or losses on projects.
Risks
Relating to our Oil and Gas Operations
Exploration
and production of oil and natural gas is a high-risk activity and is
subject
to a variety of factors that we cannot control.
Our oil and
gas business is subject to all of the risks and uncertainties normally
associated with the exploration for and development and production of oil and
natural gas, including uncertainties as to the presence, size and recoverability
of hydrocarbons. We may not encounter commercially productive oil and natural
gas reservoirs. We may not recover all or any portion of our investment in new
wells. The presence of unanticipated pressures or irregularities in formations,
miscalculations or accidents may cause our drilling activities to be
unsuccessful and/or result in a total loss of our investment, which could have a
material adverse effect on our financial condition, results of operations and
cash flows. In addition, we often are uncertain as to the future cost or timing
of drilling, completing and operating wells.
Projecting future
natural gas and oil production is imprecise. Producing oil and gas reservoirs
eventually have declining production rates. Projections of production rates rely
on certain assumptions regarding historical production patterns in the area or
formation tests for a particular producing horizon. Actual production rates
could differ materially from such projections. Production rates also can depend
on a number of additional factors, including commodity prices, market demand and
the political, economic and regulatory climate.
Our business is
subject to all of the operating risks associated with drilling for and producing
oil and natural gas, including:
|
•
|
fires;
|
||
|
•
|
title
problems;
|
||
|
•
|
explosions;
|
||
|
•
|
pressures and
irregularities in formations;
|
||
|
•
|
equipment
availability;
|
||
|
•
|
blow-outs and
surface cratering;
|
||
|
•
|
uncontrollable
flows of underground natural gas, oil and formation
water;
|
||
|
•
|
natural
events and natural disasters, such as loop currents, hurricanes and other
adverse weather conditions;
|
||
|
•
|
pipe or
cement failures;
|
||
|
•
|
casing
collapses;
|
||
|
•
|
lost or
damaged oilfield drilling and service tools;
|
||
|
•
|
abnormally
pressured formations; and
|
||
|
•
|
environmental
hazards, such as natural gas leaks, oil spills, pipeline ruptures and
discharges of toxic gases.
|
If
any of these events occurs, we could incur substantial losses as a result of
injury or loss of life, severe damage to and destruction of property, natural
resources and equipment, pollution and other environmental damage, clean-up
responsibilities, regulatory investigation and penalties, suspension of our
operations and repairs to resume operations.
Natural
gas and oil prices are volatile, which makes future revenue
uncertain.
Our financial
condition, cash flow and results of operations depend in part on the prices we
receive for the oil and gas we produce. The market prices for oil and gas are
subject to fluctuation in response to events beyond our control, such
as:
|
•
|
supply of and
demand for oil and gas;
|
||
|
•
|
market
uncertainty;
|
||
|
•
|
worldwide
political and economic instability; and
|
||
|
•
|
government
regulations.
|
Oil and gas prices
have historically been volatile, and such volatility is likely to continue. Our
ability to estimate the value of producing properties for acquisition or
disposition, and to budget and project the financial returns of exploration and
development projects is made more difficult by this volatility. In addition, to
the extent we do not forward sell or enter into costless collars or swap
contracts in order to hedge our exposure to price volatility, a dramatic decline
in such prices could have a substantial and material effect on:
|
•
|
our
revenues;
|
||
|
•
|
results of
operations;
|
||
|
•
|
cashflow;
|
||
|
•
|
financial
condition;
|
||
|
•
|
our ability
to increase production and grow reserves in an economically efficient
manner; and
|
||
|
•
|
our access to
capital.
|
If
the prices for crude oil and natural gas decrease from current levels, and we
have not entered into additional forward sale or financial hedge contracts to
stabilize our cash flows, our oil and gas revenues may decrease in 2010 and
beyond, perhaps significantly, absent offsetting increases in production
amounts.
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. We
have hedged over 50% of our anticipated production for 2010 with a combination
of costless collar and swap financial contracts. We may from time to
time engage in other hedging activities that limit our upside potential from
price increases. These hedging activities may limit our benefit from commodity
price increases.
We
are vulnerable to risks associated with the Gulf of Mexico because we
currently operate
almost exclusively in that area and our proved reserves are concentrated in a
limited number of fields.
Our concentration
of oil and gas properties in the Gulf of Mexico makes us more vulnerable to the
risks associated with operating in that area than our competitors with more
geographically diverse operations. These risks include:
|
•
|
tropical
storms and hurricanes, which are common in the Gulf of Mexico during
certain times of the year;
|
||
|
•
|
extensive
governmental regulation (including regulations that may, in certain
circumstances, impose strict liability for pollution
damage); and
|
||
|
•
|
interruption
or termination of operations by governmental authorities based on
environmental, safety or other
considerations.
|
Any event affecting
this area in which we operate our oil and gas properties may have an adverse
effect on our results of operations and cash flow. We also may incur
substantial liabilities to third parties or governmental entities, which could
have a material adverse effect on our results of operations and financial
condition.
Additionally,
approximately 98% of our estimated proved reserves are located in the Gulf of
Mexico and we have one field, Bushwood located at Garden Banks Blocks 462, 463,
506 and 507, that represents approximately half of our total estimated proved
reserves and related estimated discounted future net revenues as of December 31,
2009. If the proved reserves at Bushwood are affected by any
combination of adverse factors our future estimates of proved reserves could be
decreased, perhaps significantly, which may have an adverse effect on our future
results of operations and cash flows. Separately, without
Bushwood’s future reserve potential, the value that we may be able to realize in
any potential disposition of our oil and gas business would likely be
significantly diminished.
Estimates
of crude oil and natural gas reserves depend on many factors and assumptions,
including various assumptions that are based on conditions in existence
as
of the dates of the estimates. Any material change in those conditions, or
other factors
affecting those assumptions, could impair the quantity and value of our
crude oil
and natural gas reserves.
This Annual Report
contains estimates of our proved oil and gas reserves and the estimated future
net cash flows therefrom based upon reports for the years ended
December 31, 2009 and 2008, prepared and/or audited by our independent
petroleum engineers. These reports rely upon various assumptions, including
assumptions required by the SEC, as to oil and gas prices, drilling and
operating expenses, capital expenditures, abandonment costs, taxes and
availability of funds. The process of estimating oil and gas reserves is
complex, requiring significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and economic data for each
reservoir. As a result, these estimates are inherently imprecise. Actual future
production, cash flows, development and production expenditures, operating and
abandonment expenses and quantities of recoverable oil and gas reserves may vary
from those estimated in these reports. Any significant variance in these
assumptions could materially affect the estimated quantity and value of our
proved reserves. You should not assume that the present value of future net cash
flows from our proved reserves referred to in this Annual Report is the current
market value of our estimated oil and gas reserves. In accordance with SEC
requirements, we base the estimated discounted future net cash flows from our
proved reserves on the average of oil and gas prices on the first day of the
month for the past twelve months and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the net present
value estimate. In addition, if costs of abandonment are materially greater than
our estimates, they could have an adverse effect on financial position, cash
flows and results of operations.
Approximately
85% of our total estimated proved reserves are either PDNP, PDSI or PUD
and those
reserves may not ultimately be produced or developed.
As
of December 31, 2009, approximately 17% of our total estimated proved
reserves were PDNP, 5% were PDSI and approximately 63% were PUD. These reserves
may not ultimately be developed or produced. Furthermore, not all of our PUD or
PDNP may be ultimately produced during the time periods we have planned, at the
costs we have budgeted, or at all, which in turn may have a material adverse
effect on our results of operations.
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 85% of our
proved reserves at December 31, 2009 are PUD, PDSI and PDNP. Further, our
proved producing reserves at December 31, 2009 are expected to experience
annual decline rates ranging from 30% to 40% over the next ten years. If we are
unable to acquire additional properties or if we are unable to find additional
reserves through exploration or exploitation of our properties, our future cash
flows from oil and gas operations could decrease.
We
are, in part, dependent on third parties with respect to the transportation of
our oil and gas production and in certain cases, third party operators who
influence our productivity.
Notwithstanding our
ability to produce hydrocarbons, we are dependent on third party transporters to
bring our oil and gas production to the market. In the event a third party
transporter experiences operational difficulties, due to force majeure including
weather damage, pipeline shut-ins, or otherwise, this can directly influence our
ability to sell commodities that we are able to produce. In addition, with
respect to oil and gas projects that we do not operate, we have limited
influence over operations, including limited control over the maintenance of
safety and environmental standards. The operators of those properties may,
depending on the terms of the applicable joint operating agreement:
|
•
|
refuse to
initiate exploration or development projects;
|
||
|
•
|
initiate
exploration or development projects on a slower or faster schedule than we
would prefer;
|
||
|
•
|
delay the
pace of exploratory drilling or development; and/or
|
||
|
•
|
drill more
wells or build more facilities on a project than we can afford, whether on
a cash basis or through financing, which may limit our participation in
those projects or limit the percentage of our revenues from those
projects.
|
The occurrence of
any of the foregoing events could have a material adverse effect on our
anticipated exploration and development activities.
Our
oil and gas operations involve significant risks, and we do not have
insurance coverage
for all risks.
Our oil and gas
operations are subject to risks incident to the operation of oil and gas wells,
including, but not limited to, uncontrollable flows of oil, gas, brine or well
fluids into the environment, blowouts, cratering, mechanical difficulties,
fires, explosions or other physical damage, pollution and other risks, any of
which could result in substantial losses to us. We maintain insurance against
some, but not all, of the risks described above. As a result, any damage not
covered by our insurance could have a material adverse effect on our financial
condition, results of operations and cash flows.
Other
Risks
Other risk factors
could cause actual results to be different from the results we expect. The
market price for our common stock, as well as other companies in the oil and
natural gas industry, has been historically volatile, which could restrict our
access to capital markets in the future. Other risks and uncertainties may be
detailed from time to time in our filings with the SEC.
Many of these risks
are beyond our control. In addition, future trends for pricing, margins, revenue
and profitability remain difficult to predict in the industries we serve and
under current market, economic and political conditions. Forward-looking
statements speak only as of the date they are made and, except as required by
applicable law, we do not assume any responsibility to update or revise any of
our forward-looking statements.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
We
own a fleet of seven vessels and 39 ROVs, five trenchers, and two
ROVDrills. We also lease five vessels and one ROV. We believe that the market in
the Gulf of Mexico requires specially designed and/or equipped vessels to
competitively deliver subsea construction and well operations
services. Currently all of our vessels, both owned and leased, have
DP capabilities specifically designed to respond to the deepwater market
requirements. Two of our vessels have built-in saturation diving
systems.
Divestitures
In
March and April 2008, we sold a total 30% working interest in the Bushwood
discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental
Shelf oil and gas properties (East Cameron Blocks 371 and 381), in two separate
transactions to affiliates of a private independent oil and gas company for
total cash consideration of approximately $183.4 million (which included the
purchasers’ share of incurred capital expenditures on these fields), and
additional potential cash payments of up to $20 million based upon exceeding
specified field production milestones. The new co-owners will also
pay their pro rata share of all future capital expenditures related to the
exploration, development and decommissioning of these
fields. Decommissioning liabilities will be shared on a pro rata
share basis between the new co-owners and us. Proceeds from the sale
of these properties were used to partially repay our outstanding revolving loans
in April 2008. As a result of these sales, we recognized a pre-tax
gain of $91.6 million in the first half of 2008.
In
May 2008, we sold all our interests in our onshore proved and unproved oil and
gas properties located in the states of Texas, Mississippi, Louisiana, New
Mexico and Wyoming (“Onshore Properties”) to an unrelated third
party. We sold these Onshore Properties for cash proceeds of $47.3
million and recorded a related loss of $11.9 million in the second quarter of
2008. Proceeds from the sale of these properties were used to reduce
our outstanding revolving loans in May 2008. Included in the cost
basis of the Onshore Properties was $8.1 million of allocated goodwill from our
Oil and Gas segment.
In
December 2008, we announced the sale of all our interests in the Bass Lite field
(Atwater Block 426), a 17.5% working interest, to our joint interest owners in
the field for approximately $49 million. The sale had an effective
date of November 1, 2008. Proceeds from the sale were used to fund
our working capital requirements.
In
2009 the following divestitures were made in accordance with our announcement in
December 2008 to attempt to monetize the value of our non-core assets see “The
Industry and Our Strategy” above. Since that
announcement, we have:
|
·
|
Sold five oil
and gas properties for approximately $68 million in gross
proceeds;
|
|
·
|
Sold a total
of approximately 15.2 million shares of CDI common stock held by us to CDI
for $100 million in separate transactions in January and June 2009 (Note
3);
|
|
·
|
Sold Helix
RDS Limited, our subsurface reservoir consulting business for $25 million
in April 2009; and
|
|
·
|
Sold a total
of 45.8 million shares of CDI common stock held by us to third parties in
two separate public secondary offerings for approximately $404.4 million,
net of underwriting fees in June 2009 and September
2009.
|
OUR
VESSELS
Listing of Vessels, Barges and ROVs
Related to Contracting Services Operations(1)
|
|
Flag
State
|
Placed
in
Service(2)
|
Length
(Feet)
|
Berths
|
SAT
Diving
|
DP
|
Crane
Capacity
(tons)
|
|
CONTRACTING
SERVICES:
|
|||||||
|
Pipelay —
|
|||||||
|
Caesar (3)(4)
|
Vanuatu
|
1/2006
|
482
|
220
|
—
|
DP
|
300 and
36
|
|
Express (4)
|
Vanuatu
|
8/2005
|
531
|
132
|
—
|
DP
|
396 and
150
|
|
Intrepid (4)
|
Bahamas
|
8/1997
|
381
|
89
|
—
|
DP
|
400
|
|
Floating
Production Unit —
|
|||||||
|
Helix
Producer I (5)
|
Bahamas
|
—
|
528
|
95
|
—
|
DP
|
26 and
26
|
|
Well
Operations —
|
|||||||
|
Q4000 (6)
|
U.S.
|
4/2002
|
312
|
135
|
—
|
DP
|
160 and 360;
600 Derrick
|
|
Seawell
|
U.K.
|
7/2002
|
368
|
129
|
Capable
|
DP
|
130 and 65
Derrick
|
|
Well Enhancer
|
U.K.
|
10/2009
|
432
|
120
|
Capable
|
DP
|
100 and 150
Derrick
|
|
Robotics —
|
|||||||
|
39
ROVs, 5 Trenchers and 2 ROVDrills (4), (7)
|
—
|
Various
|
—
|
—
|
—
|
—
|
—
|
|
Olympic
Canyon (8)
|
Norway
|
4/2006
|
304
|
87
|
—
|
DP
|
150
|
|
Olympic
Triton (8)
|
Norway
|
11/2007
|
311
|
87
|
—
|
DP
|
150
|
|
Seacor
Canyon (8)
|
Majuro
Marshall Island
|
4/2007
|
221
|
40
|
—
|
DP
|
20
|
|
Island
Pioneer (8)
|
Vanuatu
|
5/2008
|
312
|
110
|
—
|
DP
|
140
|
|
(1)
|
Under
government regulations and our insurance policies, we are required to
maintain our vessels in accordance with standards of seaworthiness and
safety set by government regulations and classification organizations. We
maintain our fleet to the standards for seaworthiness, safety and health
set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds
Register of Shipping (“Lloyds”), and the USCG. 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.
|
|
(2)
|
Represents
the date we placed the vessel in service and not the date of
commissioning.
|
|
(3)
|
Vessel
conversion started in March 2007. Vessel expected to be commissioned into
our fleet in the first half of 2010.
|
|
(4)
|
Subject to
vessel mortgages (US ROVs and trenchers only) securing our Senior Credit
Facilities described in Item 8. Financial
Statements and
Supplementary Data “— Note 10 — Long-term
Debt.”
|
|
(5)
|
Former ferry
vessel near completion into DP floating production unit for
initial use on our Phoenix field. See Production Facilities on
page 30.
|
|
(6)
|
Subject to
vessel mortgage securing our MARAD debt described in Item 8. Financial
Statements and Supplementary
Data “— Note 10 — Long-term
Debt.”
|
|
(7)
|
Average age
of our fleet of ROVs, trenchers and ROV Drills is approximately
5.3 years.
|
|
(8)
|
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, 2009, 2008 and 2007:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Contracting
Services:
|
||||||||||||
|
Pipelay
|
79
|
%
|
92
|
%
|
79
|
%
|
||||||
|
Well
operations
|
82
|
%
|
70
|
%
|
71
|
%
|
||||||
|
ROVs
|
68
|
%
|
73
|
%
|
78
|
%
|
||||||
We
incur routine drydock, inspection, maintenance and repair costs pursuant to
Coast Guard regulations in order to maintain our vessels in class under the
rules of the applicable class society. In addition to complying with these
requirements, we have our own vessel maintenance program that we believe permits
us to continue to provide our customers with well maintained, reliable vessels.
In the normal course of business, we charter in other vessels on a short-term
basis, such as tugboats, cargo barges, utility boats and dive support
vessels.
PRODUCTION
FACILITIES
We
own a 50% interest in Deepwater Gateway, a limited liability company in which
Enterprise Products Partners L.P. is the other member, which owns the Marco Polo
TLP installed on Green Canyon Block 608 in 4,300 feet of water.
Deepwater Gateway was formed to construct, install and own the Marco Polo TLP in
order to process production from Anadarko Petroleum Corporation’s Marco Polo
field discovery at Green Canyon Block 608. 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, an affiliate of Enterprise Products
Partners L.P., that owns the Independence Hub platform, a 105 foot deep draft,
semi-submersible platform located in Mississippi Canyon Block 920 in a
water depth of 8,000 feet that serves as a regional hub for natural gas
production from multiple ultra-Deepwater fields in the previously untapped
eastern Gulf of Mexico. First production began in July 2007. The Independence
Hub facility is capable of processing up to 1 billion cubic feet (Bcf) per
day of gas.
Further, we, along
with Kommandor Rømø, a Danish corporation, formed a joint venture company called
Kommandor LLC and converted a ferry vessel into a floating production unit named
the Helix
Producer I.
The total cost of the vessel and initial conversion was approximately $170
million. We provided $98.9 million in interim construction
financing to the joint venture. During 2009, $58.8 million of this
amount was converted to equity in our investment in Kommandor
LLC. Our remaining loan balance to Kommandor LLC totaled $25.7
million at December 31, 2009. Kommandor Rømø provided a $5.0 million
loan to Kommandor LLC, the remaining balance of which was $3.7 million at
December 31, 2009.
Total equity
contributions and indebtedness guarantees provided by Kommandor Rømø are
expected to total $42.5 million. The remaining costs to complete the
project will be provided by us through equity contributions. Under
the terms of the operating agreement for the joint venture, Kommandor Rømø
elected not to make further contributions to the joint venture, thus the
ownership interests in the joint venture were adjusted based on the relative
contributions of each member to the total of all contributions and
project financing guarantees.
As
noted above, completion of the initial conversion of the
Helix Producer I was completed in April 2009, and we have chartered the
vessel from Kommandor LLC, and are currently installing, at 100% our cost,
processing facilities and a disconnectable fluid transfer system on the vessel
for initial use on our Phoenix field expected to commence production around
mid-year 2010. The cost of these additional facilities is estimated to range
between $190 million and $200 million (including capitalized interest of $16
million) when the work is completed. When completed, the Helix
Producer I will be capable of processing up to 45,000 barrels of oil and
70 MMcf of natural gas daily. As of December 31, 2009,
approximately $269 million of costs related to the purchase of the Helix
Producer I ($20 million), conversion of the Helix
Producer I and construction of the additional facilities had been
incurred, with an additional $12.1 million committed. The total
estimated cost of the vessel, initial conversion and the additional facilities
will range between approximately $360 million and $370
million. The results of Kommandor LLC are consolidated within
our Production Facilities segment.
SUMMARY
OF NATURAL GAS AND OIL RESERVE DATA
Recent
Accounting Rules Activities
In
December 2008, the SEC announced that it had approved revisions designed to
modernize the oil and gas company reserve reporting
requirements. In January 2010, the FASB issued Accounting
Standards Update 2010-03 “Oil and Gas Reserve Estimation and
Disclosures.” We adopted these rules on December 31, 2009 in
conjunction with our year end 2009 proved reserve estimates and have implemented
the newly mandated authoritative guidance issued by the
30
FASB on
extractive activities for oil and gas reserves estimation and
disclosures. The objective of the new guidance is to align the
oil and gas reserve estimation and disclosure requirements with the requirements
of the SEC. The most significant amendments to the requirements
included the following.
|
·
|
Commodity
prices - estimates of proved reserves and related discounted
cash flows now based on an average twelve month commodity price based on
the price of oil and gas on the first day of each month for the year the
reserve report relates;
|
|
·
|
Disclosure of
Unproved Reserves - Probable and Possible reserves may be
disclosed separately from proved reserves on a voluntary basis. We elected
not to disclose Probable and Possible
reserves;
|
|
·
|
Proved
Undeveloped Reserve Guidelines – Reserves maybe classified as proved
undeveloped reserves if there is a high degree of confidence that the
quantities will be recovered and they are scheduled to be drilled within
the next five years, unless specific circumstances justify a longer
time;
|
|
·
|
Reserves
Estimation Using New Techniques – Reserves may be estimated through a use
of reliable techniques in addition to traditional flow test and production
history;
|
|
·
|
Reserves
Personnel and Estimation Process – Additional disclosure is required
regarding the qualifications of the chief technical person who oversees
the reserve estimation process and/or the independence of the preparer of
our estimated proved reserves. We must also disclose our significant
internal controls over the reserve estimation
process;
|
|
·
|
Disclosure by
Geographic Area – Reserves in foreign countries must be presented
separately if such reserves represent more than 15% of our total estimated
oil and gas proved reserves; and
|
|
·
|
Non
Traditional Resources- The definition of oil and gas producing activities
has been expanded to include other marketable
products.
|
One effect of
adoption of these rules included the application of lower prices at December 31,
2009 for both oil and natural gas than what would have been used under the
previous rule (year end price). Generally, adoption of these
new regulations had little effect on our estimates of reserves at December 31,
2009; however, the rule requiring development of proved undeveloped reserves
within five years could significantly impact future estimates of our proved
reserves (see “Proved Undeveloped Reserves” below).
Internal
Controls Over Reserve Estimation Process
Our policies
regarding internal controls over the recording of reserves estimates requires
reserves to be in compliance with the SEC definitions and guidance and prepared
in accordance with generally accepted petroleum engineering principles.
Responsibility for compliance in reserves bookings is delegated to our Vice
President – Reservoir Engineering.
Our Vice President – Reservoir
Engineering, located in our Dallas, Texas office, prepares all reserves
estimates for all of our oil and gas properties.
Our Vice President
– Reservoir Engineering is the technical person primarily responsible for
overseeing the preparation of our reserves estimates. Our Vice President –
Reservoir Engineering has a Bachelor of Science degree in Engineering and over
15 years of industry experience with positions of increasing responsibility in
engineering and evaluations.
We
employ full-time experienced reserve engineers and geologists who are
responsible for determining proved reserves in conformance with SEC guidelines.
Engineering reserve estimates were prepared by us based upon our interpretation
of production performance data and sub-surface information derived from the
drilling of existing wells. Our internal reservoir engineers analyzed 100% of
our oil and gas fields on an annual basis (107 fields as of December 31,
2009). 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.
Lastly we engage a
third party independent reservoir engineer to review and audit our reserve
estimation process and the results of this process. At
December 31, 2009 we engaged the independent reservoir engineer to prepare their
own estimates of our proved reserves at December 31, 2009. Their
proved reserve estimates are included in this Form 10-K. The
same independent reservoir engineer audited substantially all of our estimates
of proved reserves at December 31, 2008 and 2007. See Independent
Petroleum Engineer below
Independent
Petroleum Engineer
We
have historically engaged a third party independent petroleum engineer to audit
our internal estimates of U.S. proved oil and natural gas
reserves. However, the estimates of our U.S. proved oil and
natural gas reserves at December 31, 2009 were prepared by the independent
petroleum engineering firm of Huddleston & Co.,
Inc. (“Huddleston”). We prepared the proved reserve
estimates associated with our one property in the United
Kingdom. Huddleston performed engineering audits of our
estimates of proved reserves at December 31, 2008 and 2007.
An
“engineering audit,” as we use the term, is a process involving an independent
petroleum engineering firm’s extensive visits, collection and examination of all
geologic, geophysical, engineering, production 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 process for Huddleston to prepare their
estimates of proved oil and natural gas reserves is substantially the
same as during their audit of our internal reserves (discussed
below). The primary difference between the audit and
preparation of the reserve report is that in the culmination of the audit,
Huddleston represented in its audit report that it believed our methodologies
are consistent with the methodologies required by the SEC, Society of Petroleum
Engineers (“SPE”) and FASB while in the preparation of the 2009 reserve report
we simply publish Huddleston’s estimates of our proved oil and natural gas
reserves, also in compliance with the guidelines provided by the SEC, SPE and
FASB.
The engineering
audit of our estimated proved oil and natural gas reserves (applicable for 2008
and 2007) 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 Form 10-K for the years ended December 31, 2008
and 2007 include only quantities that we expected to recover commercially using
the then mandated year-end 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 audits in 2008 and 2007, 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 it had satisfactorily resolved its questions relating
thereto or had independently verified such information or data. Furthermore, in
instances where decline curve analysis was not adequate in determining proved
producing reserves, Huddleston evaluated our volumetric analysis, which included
the analysis of production and pressure data. Each of the PUDs analyzed by
Huddleston included volumetric analysis, which took into consideration recovery
factors relative to the geology of the location and similar reservoirs. Where
applicable, Huddleston examined data related to well spacing, including
potential drainage from offsetting producing wells in evaluating proved reserves
for un-drilled well locations.
Huddleston prepared
proved reserve estimates for all of our U.S oil and gas properties at December
31, 2009. Huddleston’s report on proved reserves is included herein as Exhibit
99.1 to this Form 10-K. In 2008, the engineering audit by
Huddleston included 100% of our producing properties together with essentially
all of our non-producing and undeveloped properties in the U.S. 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 approximately 97% of the total
discounted future net revenues. Huddleston also analyzed the methods utilized by
us in the preparation of all of the estimated reserves and revenues. Huddleston
represented in its audit report that it
32
believes
our methodologies are consistent with the methodologies required by the SEC,
Society of Petroleum Engineers (“SPE”) and FASB. There were no limitations
imposed, nor limitations encountered by us or Huddleston.
The table below
sets forth the approximate estimate of our proved reserves as of
December 31, 2009. Proved reserves cannot be measured exactly
because the estimation of reserves involves numerous judgmental determinations.
Accordingly, reserve estimates must be continually revised as a result of new
information obtained from drilling and production history, new geological and
geophysical data and changes in economic conditions.
|
As
of December 31, 2009
|
||||||||||||
|
Proved
Developed Reserves
|
Proved
Undeveloped Reserves
|
Total
Proved Reserves
|
||||||||||
|
United
States:
|
||||||||||||
|
Gas
(Bcf)
|
125 | 262 | 387 | |||||||||
|
Oil
(MMBbls)
|
15 | 15 | 30 | |||||||||
|
Total
(Bcfe)
|
214 | 342 | 566 | |||||||||
|
United
Kingdom:
|
||||||||||||
|
Gas
(Bcf)
|
— | 12 | 12 | |||||||||
|
Oil
(MMBbls)
|
— | — | — | |||||||||
|
Total
(Bcfe)
|
— | 12 | 12 | |||||||||
|
Total:
|
||||||||||||
|
Gas
(Bcf)
|
125 | 274 | 399 | |||||||||
|
Oil
(MMBbls)
|
15 | 15 | 30 | |||||||||
|
Total
(Bcfe)
|
214 | 364 | 578 | |||||||||
Proved
Undeveloped Reserves (“PUDs”)
At
December 31, 2009, our PUDs totaled 274 Bcf of natural gas and 15 MMBbls of
crude oil for a total of 364 Bcfe. Our PUD’s represent 63% of our total
estimates of proved oil and natural gas reserves. All estimates
of oil and natural gas reserves are inherently imprecise and subject to change
as new technical information about the properties is
obtained. Estimates of proved reserves for wells with little or no
production history are less reliable than those based on a long production
history. Subsequent evaluation of the same reserves may result in
variations which may be substantial. This is especially valid as it
pertains to PUD reserves.
Our most
substantial PUDs are located at our Bushwood field (see “Significant
Oil and Gas Properties” below). Our Bushwood field has PUDs
totaling approximately 200 Bcfe representing approximately 74% of its total
estimated proved reserves. We had substantial changes in our Bushwood
PUD reserves in 2009 including a reclassification of 59 Bcfe from proved
developed producing (PDP) to PUD based on well production history of our Noonan
gas wells in field and new geologic data gathered throughout the
year. Separately, we also converted approximately 23 Bcfe of
our PUDs to proved developed – non producing in 2009. These
PUDs were associated with our Danny oil reservoir where production commenced in
early February 2010.
Costs incurred to
develop PUDs totaled $ 53.2 million in 2009, $154.4 million in 2008 and $98.4
million in 2007. All PUD drilling locations are expected to be
drilled pursuant with the newly enacted requirements (see “Recent Accounting
Rules Activity” above). Accordingly, estimated future
development costs related to the development of PUDs are approximately $442
million at December 31, 2009.
For additional
information regarding estimates of oil and gas reserves, including estimates of
proved developed and proved undeveloped reserves, the standardized measure of
discounted future net cash flows, and the changes in discounted future net cash
flows, see 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, 2009, we had exploration, development and
production operations in the United States, exclusively in the Gulf of
Mexico. In December 2006, we acquired the Camelot field, located in
the North Sea, in which we subsequently sold a 50% interest in June 2007. In
February 2010, we acquired our joint interest partner and as a result we own a
100% interest in the Camelot field. We are now obligated to pay the
entire abandonment obligation for the field (estimated to range between $10-15
million). The acquired entity had secured its field abandonment
obligations with a $10 million letter of credit which was fully collateralized
with cash. Camelot is our only oil and gas property in the United
Kingdom.
Our
U.S. operations accounted for over 99% of our 2009 production and
approximately 98% of total proved reserves at December 31, 2009 (85% of
such total reserves are PUDs, PDSI, and PDNP). Further, our proved producing
reserves at December 31, 2009 are expected to experience annual decline
rates ranging from 30% to 40% over the next ten years. The following table
provides a brief description of our domestic and international oil and gas
properties we consider most significant to us at December 31,
2009:
|
Development
Location
|
Net
Total Proved Reserves (Bcfe)
|
Net
Proved Reserves Mix
|
2009
Net Production (Bcfe)
|
Average
WI%
|
Expected
First Production
|
|||||||||||||||||||||
|
Oil
%
|
Gas
%
|
|||||||||||||||||||||||||
|
United
States Offshore:
|
||||||||||||||||||||||||||
|
Deepwater
|
||||||||||||||||||||||||||
|
Bushwood(1)
|
U.S.
GOM
|
270
|
11
|
89
|
6
|
51
|
Producing
|
|||||||||||||||||||
|
Phoenix(2)
|
U.S.
GOM
|
42
|
79
|
21
|
-
|
70
|
PDSI
2010
|
|||||||||||||||||||
|
Gunnison(3)
|
U.S.
GOM
|
24
|
66
|
34
|
5
|
19
|
Producing
|
|||||||||||||||||||
|
Jake
(4)
|
U.S.
GOM
|
6
|
23
|
77
|
-
|
25
|
PUD 2011
|
|||||||||||||||||||
|
Outer
Continental Shelf
|
||||||||||||||||||||||||||
|
East
Cameron 346
|
U.S.
GOM
|
35
|
80
|
20
|
2
|
75
|
Producing
|
|||||||||||||||||||
|
High
Island A557
|
U.S.
GOM
|
20
|
69
|
31
|
3
|
100
|
Producing
|
|||||||||||||||||||
|
South
Timbalier 86/63
|
U.S.
GOM
|
29
|
36
|
64
|
3
|
91
|
Producing
|
|||||||||||||||||||
|
South
Pass 89
|
U.S.
GOM
|
23
|
39
|
61
|
1
|
27
|
Producing
|
|||||||||||||||||||
|
Mobile
863
|
U.S.
GOM
|
20
|
-
|
100
|
-
|
83
|
PUD
2010
|
|||||||||||||||||||
|
West
Cameron 170
|
U.S.
GOM
|
11
|
29
|
71
|
1
|
55
|
Producing
|
|||||||||||||||||||
|
South
Marsh Island 130
|
U.S.
GOM
|
11
|
73
|
27
|
3
|
100
|
Producing
|
|||||||||||||||||||
|
Ship
Shoal 223/224
|
U.S.
GOM
|
9
|
36
|
64
|
1
|
51
|
Producing
|
|||||||||||||||||||
|
East
Cameron 339
|
U.S.
GOM
|
8
|
79
|
21
|
4
|
100
|
Producing
|
|||||||||||||||||||
|
Eugene
Island 302
|
U.S.
GOM
|
9
|
62
|
38
|
-
|
58
|
PUD
2010
|
|||||||||||||||||||
|
United Kingdom
Offshore(5)
|
UK
Offshore
|
12
|
-
|
100
|
-
|
50
|
PUD
2011
|
|||||||||||||||||||
|
(1)
|
Garden Banks
Blocks 462, 463, 506 and 507 (formerly
Noonan/Danny). Although the Bushwood field is
currently producing,
there
remains a significant amount of PUD reserves that will need to be
developed in order to sustain future production from the
field.
|
|
(2)
|
Green Canyon
Blocks 236, 237, 238 and 282.
|
|
(3)
|
An outside
operated property comprised of Garden Banks Blocks 625, 667, 668 and
669.
|
|
(4)
|
Green Canyon
Block 490.
|
|
(5)
|
Consists of
our only property in the United Kingdom, Camelot. Our
interest increased to 100% in
February 2010
when we agreed to assume our joint interest partners interest in the field
as
discussed
above.
|
United
States Offshore
Deepwater
The estimated
proved reserves associated with our four fields in the Deepwater of the Gulf of
Mexico totaled approximately 341 Bcfe or approximately 59% of our total
estimated proved reserves at December 31, 2009. We are the operator over areas
representing approximately 57% of our Deepwater proved reserves (approximately
43% of total proved reserves). We operate the Phoenix field and portions of
the Bushwood field. Gunnison, a non-operated field, has been
producing since December 2003. In 2009, we participated in the
discovery at the Jake Prospect, which is expected to be developed and commence
production in 2011. Our net production from our Deepwater properties
totaled approximately 12.3 Bcfe in 2009 as compared to 8 Bcfe in
2008.
Outer
Continental Shelf
Our estimated
proved reserves for our 102 fields in the Gulf of Mexico on the OCS totaled
approximately 225 Bcfe or 39% of our total estimated proved reserves as of
December 31, 2009. Our net production from the OCS properties totaled
approximately 31.3 Bcfe in 2009. Our largest field on the OCS is East
Cameron Block 346, whose total estimated proved reserve represents approximately
16% of our aggregated OCS estimated proved reserves (or approximately 6% of
total estimated proved reserves). The South Timbalier Blocks 86/63 field
represents approximately 13% of our total estimated OCS proved reserves (or
approximately 5% of our total estimated proved reserves). No other individual
OCS field comprised over 5% of total estimated proved reserves. We are the
operator of 80% of our OCS properties whose composite estimated proved reserves
totals approximately 179 Bcfe.
As
long as we continue to have interests in our oil and gas properties, we will
continue to advance our development activities and may pursue additional future
exploration opportunities primarily in the Deepwater of the Gulf of
Mexico.
United
Kingdom Offshore
In
December 2006, we acquired the Camelot field, located in the North Sea, of which
we subsequently sold a 50% interest in June 2007. In February 2010,
we acquired our joint interest partner and as a result we own a 100% interest in
the Camelot field. We are now obligated to pay the entire abandonment
obligation for the field (estimated to range between $10-$15 million). Camelot
is our only developed oil and gas property in the United
Kingdom. The results of our UK operations were immaterial for
each of the three years ended December 31, 2009, 2008 and 2007,
respectively.
Production,
Price and Cost Data
Production, price
and cost data for our oil and gas operations in the United States are as
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Production:
|
||||||||||||
|
Gas
(Bcf)
|
27
|
31
|
42
|
|||||||||
|
Oil
(MMBbls)
|
3
|
3
|
4
|
|||||||||
|
Total
(Bcfe)
|
44
|
47
|
65
|
|||||||||
|
Average sales
prices realized (including hedges):
|
||||||||||||
|
Gas (per
Mcf)
|
$
|
4.48
|
$
|
9.29
|
$
|
7.69
|
||||||
|
Oil (per
Bbl)
|
$
|
67.11
|
$
|
92.22
|
$
|
67.68
|
||||||
|
Total (per
Mcfe)
|
$
|
7.00
|
$
|
11.43
|
$
|
8.93
|
||||||
|
Average production cost per
Mcfe
|
$
|
2.74
|
$
|
2.60
|
$
|
1.83
|
||||||
|
Average
depletion and amortization per Mcfe
|
$
|
3.87
|
$
|
4.21
|
$
|
3.54
|
||||||
Productive
Wells
The number of
productive oil and gas wells in which we held interest as of December 31,
2009 is as follows:
|
Oil
Wells
|
Gas
Wells
|
Total
Wells
|
|||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||
|
United States – Offshore
|
276
|
218
|
302
|
156
|
578
|
374
|
|||||||||
Productive wells
are producing wells and wells capable of production. The number of
gross wells is the total number of wells in which we own a working
interest. A net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The number of net wells
is the sum of the fractional working interests owned in gross wells expressed as
whole numbers and fractions thereof. One or more completions in the same
borehole are counted as one well in this table.
The following table
summarizes non-producing wells and wells with multiple completions as of
December 31, 2009:
|
Oil
Wells
|
Gas
Wells
|
Total
Wells
|
|||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||
|
Not
producing (shut-in)
|
51
|
33
|
144
|
83
|
195
|
116
|
|||||||||
|
Multiple completions
|
16
|
7
|
53
|
22
|
69
|
29
|
|||||||||
Developed
and Undeveloped Acreage
The developed and
undeveloped acreage (including both leases and concessions) that we held at
December 31, 2009 is as follows:
|
Undeveloped
|
Developed
|
|||||||||
|
Gross
|
Net
|
Gross
|
Net
|
|||||||
|
United States – Offshore
|
235,186
|
196,255
|
457,165
|
257,633
|
||||||
|
United Kingdom – Offshore
|
25,406
|
12,703
|
9,778
|
4,889
|
||||||
|
Total
|
260,592
|
208,958
|
466,943
|
262,522
|
||||||
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):
|
Offshore
|
|||||
|
Gross
|
Net
|
||||
|
2010
|
73,686
|
60,339
|
|||
|
2011
|
30,872
|
21,416
|
|||
|
2012
|
27,275
|
21,515
|
|||
|
2013
|
30,760
|
30,760
|
|||
|
2014
|
5,760
|
5,760
|
|||
|
2015 and beyond
|
66,833
|
56,465
|
|||
|
Total
|
235,186
|
196,255
|
|||
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, 2009, 2008 and 2007:
|
Net
Exploratory Wells
|
Net
Development Wells
|
||||||||||||
|
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
||||||||
|
Year ended December 31,
2009
|
0.3
|
—
|
0.3
|
—
|
—
|
—
|
|||||||
|
Year ended December 31,
2008
|
0.4
|
0.6
|
1.0
|
2.4
|
—
|
2.4
|
|||||||
|
Year ended December 31,
2007
|
10.8
|
1.1
|
11.9
|
6.4
|
1.0
|
7.4
|
|||||||
No
wells were drilled in the United Kingdom in 2009, 2008 and 2007.
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, 2009, we had one development well in progress at our Gunnison
field. For more information regarding our oil and gas operations see
Item 8. Financial
Statements and Supplementary Data
“— Note 6 — Oil and Gas Properties.”
FACILITIES
Our corporate
headquarters are located at 400 North Sam Houston Parkway, East,
Suite 400, Houston, Texas. We own the Aberdeen (Dyce), Scotland facility
and our Spoolbase in Ingleside, Texas. All other facilities are
leased.
Properties
and Facilities Summary
|
Location
|
Function
|
Size
|
|
Houston,
Texas
|
Helix Energy
Solutions Group, Inc.
Corporate
Headquarters, Project
Management,
and Sales Office
|
92,300 square
feet
|
|
Helix Subsea
Construction, Inc.
Corporate
Headquarters
|
||
|
Energy
Resource Technology
GOM,
Inc.
Corporate
Headquarters
|
||
|
Helix
Well Ops, Inc.
Corporate
Headquarters, Project
Management,
and Sales Office
|
||
|
Kommandor LLC
(1)
Corporate
Headquarters
|
||
|
Houston,
Texas
|
Canyon
Offshore, Inc.
Corporate,
Management and Sales Office
|
1.0
acre
(Building:
24,000 square feet)
|
|
Dallas,
Texas
|
Energy
Resource Technology
GOM,
Inc.
Dallas
Office
|
25,000 square
feet
|
|
Ingleside,
Texas
|
Helix
Ingleside LLC
Spoolbase
|
120
acres
|
|
Dulac,
Louisiana
|
Energy
Resource
Technology GOM, Inc.
Shore
Base
|
20 acres
1,720 square feet
|
|
Aberdeen
(Dyce),
Scotland
|
Helix Well
Ops (U.K.) Limited
Corporate
Offices and Operations
|
3.9 acres
(Building:
42,463 square feet)
|
|
Canyon
Offshore Limited
Corporate
Offices, Operations and
Sales
Office
|
||
|
Energy
Resource Technology
U.K.
Limited
Corporate
Offices
|
||
|
Perth,
Australia
|
Well Ops SEA
Pty Ltd
Corporate
Offices
|
1.0 acre
(Building:
12,040 square feet)
|
|
Helix ESG Pty
Ltd.
Corporate
Offices
|
||
|
Rotterdam,
The
Netherlands
|
Helix Energy
Solutions BV
Corporate
Offices
|
21,600 square
feet
|
|
Singapore
|
Canyon
Offshore
International Corp
Corporate,
Operations and Sales
|
22,486 square
feet
|
|
Helix
Offshore Crewing Service Pte. Ltd.
Corporate
Headquarters
|
|
(1)
|
Kommandor LLC
is a joint venture in which we owned approximately 81% at
December 31, 2009. Kommandor LLC is included in our consolidated
results as of December 31, 2009.
|
Item 3. Legal Proceedings.
Insurance
and Litigation
Our operations are
subject to the inherent risks of offshore marine activity, including accidents
resulting in personal injury and the loss of life or property, environmental
mishaps, mechanical failures, fires and collisions. We insure against these
risks at levels consistent with industry standards. We also carry workers’
compensation, maritime employer’s liability, general liability and other
insurance customary in our business. All insurance is carried at levels of
coverage and deductibles that we consider financially prudent. Our services are
provided in hazardous environments where accidents
38
involving
catastrophic damage or loss of life could occur, and litigation arising from
such an event may result in our being named a defendant in lawsuits asserting
large claims. Although there can be no assurance that the amount of insurance we
carry is sufficient to protect us fully in all events, or that such insurance
will continue to be available at current levels of cost or coverage, we believe
that our insurance protection is adequate for our business operations. A
successful liability claim for which we are underinsured or uninsured could have
a material adverse effect on our business. We also are involved in various legal
proceedings, primarily involving claims for personal injury under the General
Maritime Laws of the United State and the Jones Act as a result of alleged
negligence. In addition, we from time to time incur other claims, such as
contract disputes, in the normal course of business.
On
December 2, 2005, we received an order from the U.S. Department of the
Interior Minerals Management Service (“MMS”) that the price threshold for both
oil and gas was exceeded for 2004 production and that royalties were due on such
production notwithstanding the provisions of the Outer Continental Shelf Deep
Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate
exploration and production of oil and natural gas in the deepwater Gulf of
Mexico by providing relief from the obligation to pay royalty on certain federal
leases up to certain specified production volumes. Our oil and gas leases
affected by this dispute are Garden Banks Blocks 667, 668 and 669
(“Gunnison”). On May 2, 2006, the MMS issued another order that superseded
the December 2005 order, and claimed that royalties on gas production are due
for 2003 in addition to oil and gas production in 2004. The order also sought
interest on all royalties allegedly due. We filed a timely notice of appeal with
respect to both the December 2005 Order and the May 2006 Order. We received an
additional order from the MMS dated September 30, 2008 stating that the price
thresholds for oil and gas were exceeded for 2005, 2006 and 2007 production and
that royalties and interest are payable as well as an additional order from the
MMS dated August 28, 2009 stating the price thresholds for oil and natural gas
were exceeded for 2008 and that royalties and interest are payable. We appealed
these orders on the same basis as the previous orders.
Other operators in
the Deepwater of the Gulf of Mexico who received notices similar to ours sought
royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison.
In March of 2006, Kerr-McGee filed a lawsuit in federal district court
challenging the enforceability of price thresholds in certain deepwater Gulf of
Mexico leases, including the Gunnison leases. On October 30, 2007, the
federal district court in the Kerr-McGee case entered judgment in favor of
Kerr-McGee and held that the Department of the Interior exceeded its authority
by including the price thresholds in the subject leases. The
government appealed the district court’s decision. On
January 12, 2009, the United States Court of Appeals for the Fifth Circuit
affirmed the decision of the district court in favor of Kerr-McGee, holding that
the DWRRA unambiguously provides that royalty suspensions up to certain
production volumes established by Congress apply to leases that qualify under
the DWRRA. After the appellate court denied a request by the
plaintiff for rehearing, the plaintiff subsequently petitioned the United States
Supreme Court for a writ of certiorari for the Supreme Court to review the Fifth
Circuit Court’s decision. In October 2009, the United States Supreme
Court announced its decision to deny the plaintiff’s writ of certiorari,
concluding the litigation in this dispute.
In
March 2009, we were notified of a third party’s intention to terminate an
international construction contract based on a claimed breach of that contract
by one of our subsidiaries. As there are substantial defenses to this
claimed breach, we cannot at this time determine if we have
any exposure under the contract. In 2010, we will
continue to assess our potential exposure to damages under this contract as the
circumstances warrant. Under the terms of the contract, our potential
liability is generally capped for actual damages at approximately $27
million Australian dollars (“AUD”) (approximately $24.3 million U.S. dollars at
December 31, 2009) and for liquidated damages at approximately $5
million AUD (approximately $4.5 million U.S. dollars at December 31,
2009). At December 31, 2009, we have a $4.0 million AUD (approximately
$3.6 million U.S. dollars at December 31, 2009) receivable against our
counterparty for work performed prior to the termination of the
contract. We continue to pursue payment for this work as well as
other claims against our counterparty. We have filed a
counterclaim that in the aggregate approximates $12.0 million U.S.
dollars.
Item 4. Submission of Matters to a Vote of Security
Holders.
None.
Executive Officers of the Company
The executive
officers of Helix are as follows:
|
Name
|
Age
|
Position
|
|
Owen Kratz
|
55
|
President and
Chief Executive Officer and Director
|
|
Bart H. Heijermans
|
43
|
Executive
Vice President and Chief Operating Officer
|
|
Robert P. Murphy
|
51
|
Executive
Vice President — Oil & Gas
|
|
Anthony Tripodo
|
57
|
Executive
Vice President and Chief Financial Officer
|
|
Alisa B. Johnson
|
52
|
Executive
Vice President, General Counsel and Corporate Secretary
|
|
Lloyd A. Hajdik
|
44
|
Senior Vice
President — Finance and Chief Accounting
Officer
|
Owen
Kratz is President and Chief Executive Officer of Helix. He
was named Executive Chairman in October 2006 and served in that capacity until
February 2008 when he resumed the position of President and Chief Executive
Officer. He was appointed Chairman in May 1998 and served as the
Company’s Chief Executive Officer from April 1997 until October
2006. Mr. Kratz served as President from 1993 until February 1999,
and has served as a Director since 1990. He served as Chief Operating
Officer from 1990 through 1997. Mr. Kratz joined Helix in 1984 and
held various offshore positions, including saturation diving supervisor, and
management responsibility for client relations, marketing and
estimating. From 1982 to 1983, Mr. Kratz was the owner of an
independent marine construction company operating in the Bay of
Campeche. Prior to 1982, he was a superintendent for Santa Fe and
various international diving companies, and a diver in the North
Sea. Mr. Kratz is also Chairman of the Board of Directors
of Cal Dive International, Inc. Mr. Kratz has a Bachelor of Science
degree from State University of New York (SUNY)
Brockport.
Bart
H. Heijermans became Executive Vice President and Chief Operating Officer
of Helix in September 2005. Prior to joining Helix, Mr. Heijermans worked
as Senior Vice President Offshore and Gas Storage for Enterprise Products
Partners, L.P. from 2004 to 2005 and previously from 1998 to 2004 was Vice
President Commercial and Vice President Operations and Engineering for GulfTerra
Energy Partners, L.P. Before his employment with GulfTerra, Mr. Heijermans
held various positions with Royal Dutch Shell in the United States, the United
Kingdom and the Netherlands. Mr. Heijermans received a Master of Science
degree in Civil and Structural Engineering from the University of Delft, the
Netherlands and is a graduate of the Harvard Business School Executive
Program.
Robert
P. Murphy was elected as Executive Vice President — Oil &
Gas of Helix on February 28, 2007, and as President and Chief Operating
Officer of Helix Oil & Gas, Inc., a wholly owned subsidiary, on
November 29, 2006. Mr. Murphy joined Helix on July 1, 2006 when
Helix acquired Remington Oil & Gas Corporation, where Mr. Murphy
served as President, Chief Operating Officer and was on the Board of Directors.
Prior to joining Remington, Mr. Murphy was Vice President —
Exploration of Cairn Energy USA, Inc, of which Mr. Murphy also served on
the Board of Directors. Mr. Murphy received a Bachelor of Science degree in
Geology from The University of Texas at Austin, and has a Master of Science in
Geosciences from the University of Texas at Dallas.
Anthony
Tripodo was elected as Executive Vice President and Chief Financial
Officer on June 28, 2008. Mr. Tripodo oversees the finance, treasury,
accounting, tax, information technology, administration and corporate planning
functions. Mr. Tripodo was a director of Helix from February 2003
until June 2008. Prior to joining Helix, Mr. Tripodo was the
Executive Vice President and Chief Financial Officer of Tesco
Corporation. From 2003 through the end of 2006, he was a Managing
Director of Arch Creek Advisors LLC, a Houston based investment banking firm.
From 2002 to 2003, Mr. Tripodo was Executive Vice President of Veritas DGC,
Inc., an international oilfield service company specializing in geophysical
services. Prior to becoming Executive Vice President, he was President of
Veritas DGC’s North and South American Group. From 1997 to 2001, he was
Executive Vice President, Chief Financial Officer and Treasurer of Veritas.
Previously, Mr. Tripodo served 16 years in various executive
capacities with Baker Hughes, including serving as Chief Financial Officer of
both the Baker Performance Chemicals and Baker Oil Tools divisions. Mr. Tripodo
graduated Summa Cum Laude with a Bachelor of Arts degree from St. Thomas
University (Miami).
Alisa
B. Johnson joined the Company as Senior Vice President, General Counsel
and Secretary of Helix in September 2006, and in November 2008 became Executive
Vice President, General Counsel and Secretary of the Company. Ms. Johnson
has been involved with the energy industry for over 19 years. Prior to
joining Helix, Ms. Johnson worked for Dynegy Inc. for nine years, at which
company she held various legal positions, including Senior Vice President and
Group General Counsel — Generation. From 1990 to 1997, Ms. Johnson
held various legal positions at Destec
40
Entergy, Inc. Prior to that
Ms. Johnson was in private law practice. Ms. Johnson received her
Bachelor of Arts degree Cum Laude from Rice University and her law degree Cum
Laude from the University of Houston.
Lloyd
A. Hajdik joined the Company in December 2003 as Vice President —
Corporate Controller. Mr. Hajdik became Chief
Accounting Officer in February 2004 and in November 2008 he became Senior Vice
President – Finance and Chief Accounting Officer. Prior to joining Helix, Mr.
Hajdik served in a variety of accounting and finance-related roles of increasing
responsibility with Houston-based companies, including NL Industries,
Inc., Compaq Computer Corporation (now Hewlett Packard), Halliburton’s Baroid
Drilling Fluids and Zonal Isolation product service lines, Cliffs
Drilling Company and Shell Oil Company. Mr. Hajdik was with
Ernst & Young LLP in the audit practice from 1989 to 1995.
Mr. Hajdik graduated Cum Laude from Texas State University receiving a
Bachelor of Business Administration degree. Mr. Hajdik is a Certified
Public Accountant and a member of the Texas Society of CPAs as well as the
American Institute of Certified Public Accountants.
PART II
Item 5. Market for the Registrant’s Common Equity, Related
Shareholder Matters
and Issuer Purchases of Equity Securities.
Our common stock is
traded on the New York Stock Exchange (“NYSE”) under the symbol “HLX.” The
following table sets forth, for the periods indicated, the high and low sale
prices per share of our common stock:
|
Common
Stock Prices
|
||||||||
|
High
|
Low
|
|||||||
|
2008
|
||||||||
|
First
Quarter
|
$ | 42.83 | $ | 28.26 | ||||
|
Second
Quarter
|
$ | 41.81 | $ | 30.54 | ||||
|
Third
Quarter
|
$ | 41.68 | $ | 28.47 | ||||
|
Fourth
Quarter
|
$ | 25.16 | $ | 3.91 | ||||
|
2009
|
||||||||
|
First
Quarter
|
$ | 9.47 | $ | 2.21 | ||||
|
Second
Quarter
|
$ | 12.65 | $ | 4.80 | ||||
|
Third
Quarter
|
$ | 16.11 | $ | 8.76 | ||||
|
Fourth
Quarter
|
$ | 16.92 | $ | 10.79 | ||||
|
2010
|
||||||||
|
First
Quarter(1)
|
$ | 13.51 | $ | 9.98 | ||||
|
(1)
|
Through
February 24, 2010
|
On
February 24, 2010, the closing sale price of our common stock on the NYSE
was $11.04 per share. As of February 17, 2010, there were an estimated 355
registered shareholders and 26,688 beneficial stockholders of our common
stock.
We
have never declared or paid cash dividends on our common stock and do not intend
to pay cash dividends in the foreseeable future. We currently intend to retain
earnings, if any, for the future operation and growth of our business. In
addition, our financing arrangements prohibit the payment of cash dividends on
our common stock. See Management’s
Discussion and Analysis of Financial Condition and Results of Operations
“— Liquidity and Capital Resources.”
Shareholder
Return Performance Graph
The following graph
compares the cumulative total shareholder return on our common stock for the
period since December 31, 2004 to the cumulative total shareholder return
for (i) the stocks of 500 large-cap corporations maintained by
Standard & Poor’s (“S&P 500”), assuming the reinvestment of
dividends; (ii) the Philadelphia Oil Service Sector index (“OSX”), a
price-weighted index of leading oil service companies, assuming the reinvestment
of dividends; and (iii) a peer group selected by us (the “Peer Group”)
consisting of the following companies: Global Industries, Ltd., Oceaneering
International, Inc., Cameron International Corporation, Pride International,
Inc., Oil States International, Inc., FMC Technologies, Inc., McDermott
International, Inc., Rowan Companies, Inc., Tidewater Inc., ATP Oil &
Gas Corporation, W&T Offshore, Inc. and Mariner Energy, Inc. The returns of
each member of the Peer Group have been weighted according to each individual
company’s equity market capitalization as of December 31, 2009 and have
been adjusted for the reinvestment of any dividends. We believe that the members
of the Peer Group provide services and products more comparable to us than those
companies included in the OSX. The graph assumes $100 was invested on
December 31, 2004 in our common stock at the closing price on that date
price and on December 31, 2004 in the three indices presented. We paid no
cash dividends during the period presented. The cumulative total percentage
returns for the period presented were as follows: our stock — (42.4%); the
Peer Group — 131.6%; the OSX — 58.4%; and S&P 500- 3.0%. These
results are not necessarily indicative of future performance.
Comparison
of Five Year Cumulative Total Return among Helix, S&P 500,
OSX
and Peer Group
|
As
of December 31,
|
|||||||||||||||||||||||
|
2004
|
2005
|
2006
|
2007
|
2008
|
2009
|
||||||||||||||||||
|
Helix
|
$
|
100.0
|
$
|
177.8
|
$
|
154.3
|
$
|
200.8
|
$
|
33.6
|
$
|
57.6
|
|||||||||||
|
Peer Group Index
|
$
|
100.0
|
$
|
159.7
|
$
|
200.5
|
$
|
312.1
|
$
|
116.1
|
$
|
231.6
|
|||||||||||
|
Oil Service Index
|
$
|
100.0
|
$
|
146.3
|
$
|
163.0
|
$
|
247.4
|
$
|
96.9
|
$
|
158.4
|
|||||||||||
|
S&P 500
|
$
|
100.0
|
$
|
105.3
|
$
|
121.9
|
$
|
128.8
|
$
|
79.5
|
$
|
103.0
|
|||||||||||
Source:
Bloomberg
Issuer
Purchases of Equity Securities
|
Period
|
(a)
Total number
of
shares
purchased
|
(b)
Average
price
paid
per
share
|
(c)
Total number
of
shares
purchased
as
part
of publicly
announced
program
(2)
|
(d)
Maximum
number
of shares
that
may yet be
purchased
under
the program (3)
|
||||||
|
October 1 to October 31,
2009(1)
|
64,983
|
$
|
15.01
|
63,000
|
619,569
|
|||||
|
November 1 to November 30,
2009(1)
|
168,265
|
14.32
|
168,000
|
451,569
|
||||||
|
December 1 to December 31,
2009(1)
|
─
|
─
|
─
|
451,569
|
||||||
|
233,248
|
$
|
14.51
|
231,000
|
451,569
|
|
(1)
|
Represents
shares delivered to the Company by employees in satisfaction of minimum
withholding taxes and upon forfeiture of restricted
shares.
|
|
(2)
|
In June 2009,
we announced that we intend to purchase 1.5 million share of our common
stock as permitted under our senior credit facility (Note
15).
|
|
(3)
|
Amount as of
December 31, 2009. In January 2010, we issued
approximately 0.5 million shares to certain of our
employees. These grants will increase the number of shares
available for repurchase by a corresponding amount (Note
13).
|
Item 6. Selected Financial Data.
The financial data
presented below for each of the five years ended December 31, 2009, should
be read in conjunction with Item 7. Management’s
Discussion and Analysis
of Financial Condition and Results of Operations and Item 8. Financial
Statements
and Supplementary Data included elsewhere in this Annual Report on Form
10-K.
|
Year
Ended December 31, 2009
|
|||||||||||||||||||
|
2009
(1)
|
2008
|
2007
|
2006(2)
|
2005
|
|||||||||||||||
|
(amounts
in thousands, except per share data)
|
|||||||||||||||||||
|
Net revenues
|
$
|
1,461,687
|
$
|
2,114,074
|
$
|
1,732,420
|
$
|
1,328,136
|
$
|
793,860
|
|||||||||
|
Gross profit
|
243,162
|
372,191
|
505,907
|
503,478
|
281,737
|
||||||||||||||
|
Operating income (loss)
(3)
|
203,815
|
(414,222
|
)
|
411,279
|
392,061
|
221,233
|
|||||||||||||
|
Equity in earnings of
investments
|
32,329
|
31,854
|
19,573
|
17,927
|
13,425
|
||||||||||||||
|
Income (loss)
from continuing operations
|
166,170
|
(580,245
|
)
|
343,639
|
338,816
|
152,199
|
|||||||||||||
|
Income (loss)
from discontinued operations, net of taxes
|
9,581
|
(9,812
|
)
|
1,347
|
4,806
|
369
|
|||||||||||||
|
Net income (loss), including
noncontrolling interests(4)
|
175,751
|
(590,057
|
)
|
344,986
|
343,622
|
152,568
|
|||||||||||||
|
Net income
loss applicable to noncontrolling interests
|
(19,697
|
)
|
(45,873
|
)
|
(29,288
|
)
|
(725
|
)
|
─
|
||||||||||
|
Net income
(loss) applicable to Helix
|
156,054
|
(635,930
|
)
|
315,698
|
342,897
|
152,568
|
|||||||||||||
|
Preferred
stock dividends and accretion
|
(54,187
|
)
|
(3,192
|
)
|
(3,716
|
)
|
(3,358
|
)
|
(2,454
|
)
|
|||||||||
|
Net income (loss) applicable
to Helix common shareholders(4)
|
$
|
101,867
|
$
|
(639,122
|
)
|
$
|
311,982
|
$
|
339,539
|
$
|
150,114
|
||||||||
|
Year
Ended December 31, 2009
|
|||||||||||||||||||
|
2009
(1)
|
2008
|
2007
|
2006(2)
|
2005
|
|||||||||||||||
|
(amounts
in thousands, except per share data)
|
|||||||||||||||||||
|
Basic
earnings (loss) per share of common stock (4):
|
|||||||||||||||||||
|
Continuing
operations
|
$
|
0.92
|
(6.94
|
)
|
$
|
3.40
|
$
|
3.92
|
$
|
1.93
|
|||||||||
|
Discontinued
operations
|
0.09
|
(0.11
|
)
|
0.02
|
0.06
|
─
|
|||||||||||||
|
Net income
per common share
|
$
|
1.01
|
$
|
(7.05
|
)
|
$
|
3.42
|
$
|
3.98
|
$
|
1.93
|
||||||||
|
Diluted
earnings (loss) per share of common stock (4):
|
|||||||||||||||||||
|
Continuing
operations
|
$
|
0.87
|
$
|
(6.94
|
)
|
$
|
3.25
|
$
|
3.74
|
$
|
1.85
|
||||||||
|
Discontinued
operations
|
0.09
|
(0.11
|
)
|
0.01
|
0.05
|
0.01
|
|||||||||||||
|
Net income
per common share
|
$
|
0.96
|
$
|
(7.05
|
)
|
$
|
3.26
|
$
|
3.79
|
$
|
1.86
|
||||||||
|
Weighted
average common shares outstanding(4):
|
|||||||||||||||||||
|
Basic
|
99,136
|
90,650
|
90,086
|
84,613
|
77,444
|
||||||||||||||
|
Diluted
|
105,720
|
90,650
|
95,647
|
89,714
|
81,965
|
||||||||||||||
|
(1)
|
Excludes the
results of Cal Dive subsequent to June 10, 2009 following its
deconsolidation from our consolidated financial statements (Notes 1, 2 and
3).
|
|
(2)
|
Includes
effect of the Remington acquisition since July 1,
2006.
|
|
(3)
|
Total oil and
gas property impairment charges totaled $120.6 million, $920.0 million,
$64.1 million and $0.8 million for each of the years ending
December 31, 2009, 2008, 2007, and 2005, respectively. There
were no impairments in 2006. We recorded a total of $55.9 million of oil
and gas property impairment charge in the fourth quarter of
2009. Our impairments in 2008 included $896.9 million of
impairment charges to reduce goodwill ($704.3 million) and certain oil and
gas properties ($192.6 million) to their estimated fair value in fourth
quarter of 2008. Also includes exploration expenses
totaling $24.4 million in 2009 ($21.5 million in
fourth quarter of 2009), $32.9 million in 2008, $26.7 million in 2007,
$43.1 million in 2006, $6.5 million in 2005.
|
|
|
|
|
(4)
|
Includes
$77.3 million of gains on the sales of Cal Dive common stock held by us in
2009 (Note 3). Also includes the impact of gains on subsidiary
equity transactions of $98.5 million and $96.5 million for the
year ended December 31, 2007 and 2006, respectively. The gains were
derived from the difference in the value of our investment in CDI
immediately before and after its issuance of stock related to its
acquisition of Horizon and its initial public offering.
|
|
(5)
|
All earnings
per share information reflects a two-for-one stock split effective as of
the close of business on December 8,
2005.
|
|
As
of December 31,
|
|||||||||||||||||
|
2009
(1)
|
2008(2)
|
2007
|
2006(3)
|
2005
|
|||||||||||||
|
(In
thousands)
|
|||||||||||||||||
|
Working
capital
|
$
|
197,072
|
$
|
287,225
|
$
|
48,290
|
$
|
310,524
|
$
|
120,388
|
|||||||
|
Total
assets
|
3,779,533
|
5,067,066
|
(2)
|
5,449,515
|
4,287,783
|
1,660,864
|
|||||||||||
|
Long-term
debt and capital leases (including current maturities)
|
1,360,739
|
2,027,226
|
1,758,186
|
1,431,235
|
447,171
|
||||||||||||
|
Convertible
preferred
stock
|
6,000
|
(4)
|
55,000
|
55,000
|
55,000
|
55,000
|
|||||||||||
|
Total
controlling interest shareholders’ equity
|
1,405,257
|
1,191,149
|
(2)
|
1,829,951
|
1,556,314
|
629,300
|
|||||||||||
|
Noncontrolling
interests
|
22,205
|
322,627
|
263,926
|
59,802
|
─
|
||||||||||||
|
Total equity
|
1,427,462
|
1,513,776
|
2,093,877
|
(5)
|
1,616,116
|
(5)
|
629,300
|
||||||||||
|
(1)
|
Reflects
deconsolidation of Cal Dive effective June 10, 2009 (Notes 1,2 and
3).
|
|
(2)
|
Includes the
$907.6 million of impairment charges recorded in fourth quarter to reduce
goodwill, intangible assets with indefinite lives and certain oil and gas
properties to their estimated fair values. See Item 8.
Financial
Statements
and Supplementary Data “— Note 2 — Summary of
Significant Accounting Policies.” for additional
information.
|
|
(3)
|
Includes
effect of the Remington acquisition since July 1,
2006.
|
|
(4)
|
The holder of
the convertible preferred stock redeemed $49 million of our convertible
preferred stock into 12.8 million shares of our common stock in
2009. See Item 8. Financial
Statements
and Supplementary Data “— Note 12 — Convertible
Preferred Stock” for additional information.
|
|
(5)
|
Total equity
amount includes a January 1, 2006 $34.9 million cumulative effect on
change of accounting principle to reflect the adoption of ASC Topic No.
470-20.
|
Item 7. Management’s Discussion and Analysis of Financial Condition
and Results
of Operation
The
following management’s discussion and analysis should be read in conjunction
with our
historical consolidated financial statements located in Item 8. “Financial
Statements and Supplementary Data” of this report. Any reference to Notes in the
following management’s discussion and analysis refers to the Notes to
Consolidated Financial Statements located in Item 8. “Financial Statements and
Supplementary Data” of this report. The results of operations
reported and summarized below are not necessarily indicative of future operating
results. This discussion also contains forward-looking statements
that reflect our current
views with respect to future events and financial performance. Our actual
results
may differ materially from those anticipated in these forward-looking
statements
as a result of certain factors, such as those set forth under Item
1A. “Risk Factors”
and located earlier in this report.
Executive
Summary
Our
Business
We
are an international offshore energy company that provides reservoir development
solutions and other contracting services to the energy market as well as to our
own oil and gas properties. Our oil and gas business is a prospect generation,
exploration, development and production company. Employing our own key services
and methodologies, we seek to lower finding and development costs, relative to
industry norms.
Our
Strategy
In
December 2008, we announced our intention to focus and shape the future
direction of the Company around our deepwater construction and well intervention
services that comprise our Contracting Services business. We intend
to achieve this strategic focus by seeking and evaluating strategic
opportunities to sell certain non-core assets, such as:
|
·
|
all or
a portion of our oil and gas
assets;
|
|
·
|
our
ownership interests in one or more of our production facilities;
and
|
|
·
|
our
remaining interest in CDI.
|
We also
announced that economic and financial market conditions may affect the timing of
any strategic dispositions by us and therefore a degree of patience would be
required in order to execute any transactions. We continue to
focus on reducing debt levels through monetization of non-core assets and
allocation of free cash flow in order to accelerate our strategic
goals.
Since the
announcement of our strategy to monetize certain of our non core business
assets, we have:
|
·
|
Sold five oil
and gas properties for approximately $68 million in gross
proceeds;
|
|
·
|
Sold a total
of 15.2 million shares of CDI common stock held by us to CDI for $100
million in separate transactions in January and June 2009 (Note
3);
|
|
·
|
Sold Helix
RDS Limited, our subsurface reservoir consulting business for $25 million
in April 2009; and
|
|
·
|
Sold a total
of 45.8 million shares of CDI common stock held by us to third parties in
two separate public secondary offerings for approximately $404.4 million,
net of underwriting fees in June 2009 and September
2009.
|
Demand for our
contracting services operations is primarily influenced by the condition of the
oil and gas industry, and in particular, the willingness of oil and gas
companies to make capital expenditures for offshore exploration, drilling and
production operations. Generally, spending for our contracting
services fluctuates directly with the direction of oil and natural gas prices.
The performance of our oil and gas operations is also largely dependent on the
prevailing market prices for oil and natural gas, which are impacted by global
economic conditions, hydrocarbon production and excess capacity, geopolitical
issues, weather and several other factors.
Economic
Outlook and Industry Influences
The continued
economic downturn and general weakness in the equity and credit capital markets
has led to continued uncertainty regarding the outlook of the global
economy. This uncertainty coupled with the negative near-term outlook
for global demand for oil and natural gas resulted in commodity price declines
in 2008. Prices for oil increased in the second and third quarters of 2009 but
remain significantly lower than the high prices achieved in second and third
quarters of 2008. Natural gas prices continued to decline in
2009 with prices reaching near decade low levels in the third quarter of
2009. Natural gas prices increased moderately in the fourth quarter
of 2009 and now compare favorably with prices in effect before the price
decreases in the second and third quarters of 2009 but still significantly below
the record high prices received in 2008. A decline in oil and gas prices
negatively impacts our operating results and cash flow. Further, our
contracting services operations are negatively impacted by declining commodity
prices, which has resulted in some of our customers, primarily oil and gas
companies, to announce reductions in near term capital spending. The
long-term fundamentals for our business remain generally favorable as the
continual effort to replenish oil and gas production should drive demand for our
services. In addition, our subsea construction operations primarily
support capital projects with long lead times that are less likely to be
impacted by temporary economic downturns. Separately, we have hedged
significant portion of our anticipated oil and natural gas production for 2010
through the placement of swap and costless collar financial hedge contracts
(Note 2).
At
December 31, 2009, we had cash on hand of $270.7 million and $385.8 million
available for borrowing under our revolving credit
facilities. Our capital expenditures for 2010 are expected to
total approximately $200 million and reflect the final construction
payments for our Well
Enhancer, Caesar
and Helix
Producer
I vessels and the development of two of our significant deepwater oil and
gas properties expected to commence production in 2010 (one achieved first
production on February 2, 2010 and the other’s initial production is expected
around mid-year 2010). If we successfully implement our
business plan, we believe we have sufficient liquidity without incurring
additional indebtedness beyond the existing capacity under the Revolving Credit
Facility.
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 expenditures 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, including available access to global capital and
capital markets;
|
||
|
•
|
demand for
oil and natural gas, especially in the United States, Europe, China and
India;
|
||
|
•
|
the capacity
and ability to store excess North American natural gas supply within
existing storage;
|
||
|
•
|
economic and
political conditions in the Middle East and other oil-producing
regions;
|
||
|
•
|
actions taken
by the OPEC;
|
||
|
•
|
the
availability and discovery rate of new oil and natural gas reserves in
offshore areas;
|
||
|
•
|
the cost of
offshore exploration for and production and transportation of oil and
gas;
|
||
|
•
|
the ability
of oil and natural gas companies to generate funds or otherwise obtain
external capital for exploration, development and production
operations;
|
||
|
•
|
the sale and
expiration dates of offshore leases in the United States and
overseas;
|
||
|
•
|
technological
advances affecting energy exploration production transportation and
consumption;
|
||
|
•
|
weather
conditions;
|
||
|
•
|
environmental
and other governmental regulations; and
|
||
|
•
|
tax
policies.
|
Global economic
conditions deteriorated significantly over the second half of 2008 with declines
in the oil and gas market accelerating during the fourth quarter of 2008 and
continuing into 2009. Oil prices partially recovered in the second and third
quarters of 2009 and natural gas prices increased in the fourth quarter of 2009
but the current price for both commodities remains low relative to amounts
realized in 2008. Predicting the timing and sustainability of any
recovery in pricing is subjective and highly uncertain. Although we
are still feeling the effects of the recent recession, we believe that the
long-term industry fundamentals are positive based on the following factors: (1)
long term increasing world demand for oil and natural gas; (2) peaking
global production rates; (3) globalization of the natural gas market;
(4) increasing number of mature and small reservoirs; (5) increasing
offshore activity, particularly in deepwater; and (6) increasing number of
subsea developments. Our strategy of combining contracting services operations
and oil and gas operations allows us to focus on trends (4) through
(6) in that we pursue long-term sustainable growth by applying specialized
subsea services to
46
the
broad external offshore market but with a complementary focus on marginal fields
and new reservoirs in which we currently have an equity
stake.
Business
Activity Summary
Over the last few
years we have continued to evolve our model by completing a variety of
transactions and actions that we believe will continue to have significant
impacts on our results of operations and financial condition. In
2005, we acquired a significant mature property package in the Gulf of Mexico
OCS from Murphy Oil Corporation for $163.5 million cash and assumption of
abandonment liability of $32 million. In 2006, we acquired
Remington, an exploration, development and production company, for approximately
$1.4 billion in cash and Helix common stock and the assumption of
$358.4 million of liabilities. In March 2006, we changed our name from
Cal Dive International, Inc. to Helix Energy Solutions Group, Inc., leaving
the “Cal Dive” name to our former Shelf Contracting subsidiary (see
“Reduction in Ownership of Cal Dive” below), and in December 2006 completed a
carve-out initial public offering of Cal Dive, selling a 26.5% stake and
receiving pre-tax net proceeds of $264.4 million and a pre-tax dividend of
$200 million from additional borrowings under the Cal Dive revolving
credit facility.
During 2006 we
committed to four capital projects that have expanded and will continue to
significantly expand our contracting services capabilities:
|
·
|
conversion of
the Caesar
into a deepwater pipelay vessel; the Caesar
is expected to be commissioned into our fleet in the first half of
2010;
|
|
·
|
upgrading of
the Q4000
to include drilling
capability;
|
|
·
|
conversion of
a ferry vessel into a DP floating production unit (Helix
Producer I); the Helix
Producer I is expected to commence service around mid-year 2010;
and
|
|
·
|
construction
of a multi-service DP dive support/well intervention vessel (Well
Enhancer). The Well
Enhancer joined our fleet in October
2009.
|
During 2007, we
successfully completed the drilling of exploratory wells in our Bushwood
prospect located in Garden Banks Blocks 462, 463, 506 and 507 in the Gulf of
Mexico. In January 2009, we announced an additional discovery at the Bushwood
field (see “Oil and Gas Operations” in Item 2. “Properties” elsewhere in this
Form 10-K). Initial sustained production from Bushwood commenced in January
2009. Production from the Bushwood field increased subsequent
to year end 2009 following completion of long delayed repairs of a third party
pipeline providing service to the field and our development of a substantial
portion of our proved undeveloped oil reserves at the
field. Oil production from the Danny reservoir within the
Bushwood field commenced in early February 2010. We are currently
working to restore production at the Phoenix field at Green Canyon Blocks 236,
237, 238 and 282 around mid-year 2010 using the Helix
Producer I as the field’s production unit.
Reduction
in Ownership of Cal Dive
At December 31, 2008, we owned 57.2%
of Cal Dive. In January 2009, we sold approximately 13.6 million
shares of Cal Dive common stock held by us to Cal Dive for $86
million. This transaction constituted a single transaction and was
not part of any planned set of transactions that would result in us having a
noncontrolling interest in Cal Dive, and reduced our ownership in Cal Dive to
approximately 51%. Since we retained control of CDI immediately after
the transaction, the approximate $2.9 million loss on this sale was treated as a
reduction of our equity in the accompanying consolidated balance
sheet.
In
June 2009, we sold 22.6 million shares of Cal Dive held by us pursuant to an
underwritten secondary public offering (“Offering”). Proceeds
from the Offering totaled approximately $182.9 million, net of underwriting
fees. Separately, pursuant to a Stock Repurchase Agreement with Cal
Dive, simultaneously with the closing of the Offering, Cal Dive repurchased from
us approximately 1.6 million shares of its common stock for net proceeds of $14
million at $8.50 per share, the Offering price. Following the closing of these
two transactions, our ownership of Cal Dive common stock was reduced to
approximately 26%.
Because these
transactions reduced our ownership in Cal Dive to less than 50%, the $59.4
million gain resulting from the sale of these shares is reflected in “Gain on
sale of Cal Dive common stock” in the accompanying consolidated statement of
operations. Because we no longer held a controlling interest in Cal
Dive, we ceased consolidating Cal Dive
47
effective June 10,
2009, the closing date of the Offering, and we commenced accounting for our
remaining ownership interest in Cal Dive under the equity method of accounting
until September 23, 2009 as discussed below.
On
September 23, 2009, we sold 20.6 million shares of Cal Dive common stock held by
us pursuant to a second secondary public offering (“Second
Offering”). On September 24, 2009, the underwriters sold
an additional 2.6 million shares of Cal Dive common stock held by us pursuant to
their overallotment option under the terms of the Second
Offering. The price for the Second Offering was $10 per share,
with resulting proceeds totaling approximately $221.5 million, net of
underwriting fees. We recorded a $17.9 million gain associated with
the Second Offering transactions which was recorded as a component of “Gain on
sale of Cal Dive common stock” in the accompanying consolidated statement of
operations.
For more
information regarding the reduction in our ownership in Cal Dive see Notes 1, 2
and 3 .
Results
of Operations
Our operations are
conducted through two lines of business: contracting services and oil and gas.
We have disaggregated our contracting services operations into three reportable
segments in accordance with FASB Codification (“ASC”) Topic No. 280 Segment
Reporting. As a result, our reportable segments consisted of
the following: Contracting Services, Shelf Contracting, and Production
Facilities as well as Oil and Gas. As discussed below, in June
2009, we ceased consolidating our Shelf Contracting segment, which represented
the results and operations of Cal Dive, following the sale of a substantial
amount of our remaining ownership of Cal Dive (Note 3). Each line
item within our consolidated statement of operations for the year ended December
31, 2009 is impacted significantly when compared to the year ended December 31,
2008 as a result of the deconsolidation of the Cal Dive results. Our
2009 consolidated results include Cal Dive’s results through June 10, 2009,
while we recorded our approximate 26% share of Cal Dive’s results for the period
June 11, 2009 through September 23, 2009 to equity in earnings of investments as
required under the equity method of accounting. We continued to
disclose the operating results of the Shelf Contracting business as a segment
through June 10, 2009.
All material
intercompany transactions between the segments have been eliminated in our
consolidated financial statements, including our consolidated results of
operations.
Contracting
Services Operations
We
seek to provide services and methodologies, which we believe are critical to
finding and developing offshore reservoirs and maximizing production
economics. The Contracting Services segment includes operations such
as subsea construction, well operations, robotics and drilling. The
Cal Dive assets, representing our former Shelf Contracting segment, are deployed
primarily for diving-related activities and shallow water
construction. Our Contracting Services business operates primarily in
the Gulf of Mexico, the North Sea, Asia Pacific and West Africa regions, with
services that cover the lifecycle of an offshore oil or gas field. As
of December 31, 2009, our contracting services operations had backlog of
approximately $251 million, including $217 million for 2010. These
backlog contracts are cancellable without penalty in many
cases. Backlog is not a reliable indicator of total annual revenue
for our Contracting Services businesses as contracts may be added, cancelled and
in many cases modified while in progress.
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 of our
contracting services business and to achieve incremental returns. We
have evolved this business model to include not only mature oil and gas
properties but also proved and unproved reserves yet to be developed and
explored. By owning oil and gas reservoirs and prospects, we are able
to utilize the services we otherwise provide to third parties to create value at
key points in the life of our own reservoirs including during the exploration
and development stages, the field management stage and the abandonment
stage. It is also a feature of our business model to
opportunistically monetize part of the created reservoir value, through sales of
working interests, in order to help fund field development and reduce gross
profit deferrals from our Contracting Services operations. Therefore
the reservoir value we create is realized through oil and gas production and/or
monetization of working interest stakes.
Discontinued
Operations
On April 27, 2009, we sold Helix RDS
Limited, our former reservoir technology consulting company, to a subsidiary of
Baker Hughes Incorporated for $25 million. We have presented the
results of Helix RDS as discontinued operations in the accompanying condensed
consolidated financial statements (Note 2). Helix RDS was
previously a component of our Contracting Services business. We
recognized an $8.3 million gain on the sale of Helix RDS. The
operating results of Helix RDS were immaterial for all periods presented in this
Form 10-K.
Comparison
of Years Ended December 31, 2009 and 2008
The following table
details various financial and operational highlights for the periods
presented:
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
|||||||||
|
2009
|
2008
|
|||||||||
|
Revenues (in
thousands) –
|
||||||||||
|
Contracting
Services
|
$
|
796,158
|
$
|
961,926
|
$
|
(165,768
|
)
|
|||
|
Shelf
Contracting(1)
|
404,709
|
856,906
|
(452,197
|
)
|
||||||
|
Oil and
Gas
|
385,338
|
545,853
|
(160,515
|
)
|
||||||
|
Production
facilities
|
17,248
|
─
|
17,248
|
|||||||
|
Intercompany
elimination
|
(141,766
|
)
|
(250,611
|
)
|
108,845
|
|||||
|
$
|
1,461,687
|
$
|
2,114,074
|
$
|
(652,387
|
)
|
||||
|
Gross
profit (loss) (in thousands) –
|
||||||||||
|
Contracting
Services
|
$
|
148,375
|
$
|
208,448
|
$
|
(60,073
|
)
|
|||
|
Shelf
Contracting(1)
|
92,728
|
254,007
|
(161,279
|
)
|
||||||
|
Oil and
Gas(2)
|
21,788
|
(60,601
|
)
|
82,389
|
||||||
|
Production
facilities
|
(3,478
|
)
|
─
|
(3,478
|
)
|
|||||
|
Corporate
|
(2,797
|
)
|
(3,652
|
)
|
855
|
|||||
|
Intercompany
elimination
|
(13,454
|
)
|
(26,011
|
)
|
12,557
|
|||||
|
$
|
243,162
|
$
|
372,191
|
$
|
(129,029
|
)
|
||||
|
Gross Margin
–
|
||||||||||
|
Contracting
Services
|
19
|
%
|
22
|
%
|
(3
|
)pts
|
||||
|
Shelf
Contracting(1)
|
23
|
%
|
30
|
%
|
(7
|
)pts
|
||||
|
Oil and Gas
(2)
|
6
|
%
|
(11)
|
%
|
17
|
pts
|
||||
|
Production
facilities
|
(20)
|
%
|
─
|
(20
|
)
pts
|
|||||
|
Total
company
|
17
|
%
|
18
|
%
|
(1
|
)pt
|
||||
|
Number of
vessels(3)/
Utilization(4)
–
|
||||||||||
|
Contracting
Services:
|
||||||||||
|
Pipelay
|
7/79
|
%
|
9/92
|
%
|
||||||
|
Well
operations
|
3/82
|
%
|
2/70
|
%
|
||||||
|
ROVs/Trenchers/ROVDrill
Units
|
47/68
|
%
|
46/73
|
%
|
||||||
|
Shelf
Contracting
|
N/A
|
30/60
|
%
|
|||||||
|
1)
|
Represented
by our former majority-owned subsidiary, CDI. At December 31,
2008 our ownership interest in CDI was approximately
57.2%. We consolidated CDI until June 2009, at which
time we deconsolidated CDI from our financial statements after
we reduced our ownership interest in CDI to below 50% (see “Reduction in
Ownership of Cal Dive” above and Note 3).
|
|
2)
|
Included
asset impairment charges of oil and gas properties totaling $120.6 million
in 2009 and $215.7 million in 2008. These impairments charges
included $55.9 million in 2009 and $192.6 in 2008 recorded in
the respective fourth quarter periods. These impairment charges
do not have any impact on current or future cash flow.
|
|
3)
|
Represented
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.
|
|
4)
|
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, 2009 and 2008 were as
follows (in thousands):
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
|||||||||
|
2009
|
2008
|
|||||||||
|
Contracting Services
|
$
|
120,048
|
$
|
195,207
|
$
|
(75,159
|
)
|
|||
|
Production Facilities
|
13,853
|
─
|
13,853
|
|||||||
|
Shelf Contracting(1)
|
7,865
|
55,404
|
(47,539
|
)
|
||||||
|
$
|
141,766
|
$
|
250,611
|
$
|
(108,845
|
)
|
||||
|
1)
|
Represented
by our former majority-owned subsidiary, CDI. At December 31,
2008 our ownership interest in CDI was approximately
57.2%. We consolidated CDI until June 2009, at which
time we deconsolidated CDI from our financial statements after
we reduced our ownership interest in CDI to below 50% (see “Reduction in
Ownership of Cal Dive” above and Note
3).
|
Intercompany
segment profit (which only relates to intercompany capital projects) during the
years ended December 31, 2009 and 2008 were as follows (in
thousands):
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
||||||||
|
2009
|
2008
|
||||||||
|
Contracting Services
|
$
|
13,205
|
$
|
20,945
|
$
|
(7,740
|
)
|
||
|
Shelf Contracting(1)
|
365
|
5,066
|
(4,701
|
)
|
|||||
|
Production Facilities
|
(116
|
)
|
─
|
(116
|
)
|
||||
|
$
|
13,454
|
$
|
26,011
|
$
|
(12,557
|
)
|
|||
|
1)
|
Represented
by our former majority-owned subsidiary, CDI. At December 31,
2008 our ownership interest in CDI was approximately
57.2%. We consolidated CDI until June 2009, at which
time we deconsolidated CDI from our financial statements after
we reduced our ownership interest in CDI to below 50% (see “Reduction in
Ownership of Cal Dive” above and Note
3).
|
As
disclosed in Item 2 “Properties” elsewhere in this Form 10-K, virtually all of
our oil and gas operations are located in the U.S. Gulf of Mexico. We
have one property located offshore of the United Kingdom, Camelot, that is
capable of production but has been shut-in for substantially all of
both 2009 and 2008. Revenues associated with our U.K oil and gas
operations totaled $1.0 million in 2009 and $3.9 million in 2008 on
production volumes of 0.2 Bcfe and 0.3 Bcfe,
respectively. The total operating costs associated with our U.K oil
and gas operations totaled $3.7 million in 2009 and $4.1 million in
2008.
The following table
details various financial and operational highlights related to our Oil and Gas
segment for the periods presented:
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
||||||||||
|
2009
|
2008
|
||||||||||
|
Oil and Gas
information–
|
|||||||||||
|
Oil
production volume (MBbls)
|
2,741
|
2,752
|
(11
|
)
|
|||||||
|
Oil sales
revenue (in thousands)
|
$
|
183,973
|
$
|
253,762
|
$
|
(69,789
|
)
|
||||
|
Average
oil sales price per Bbl (excluding hedges)
|
$
|
64.15
|
$
|
98.62
|
$
|
(34.47
|
)
|
||||
|
Average
realized oil price per Bbl (including hedges)
|
$
|
67.11
|
$
|
92.22
|
$
|
(25.11
|
)
|
||||
|
Decrease
in oil sales revenue due to:
|
|||||||||||
|
Change
in prices (in thousands)
|
$
|
(69,100
|
)
|
||||||||
|
Change
in production volume (in thousands)
|
(689
|
)
|
|||||||||
|
Total
decrease in oil sales revenue (in thousands)
|
$
|
(69,789
|
)
|
||||||||
|
Gas
production volume (MMcf)
|
27,334
|
30,823
|
(3,489
|
)
|
|||||||
|
Gas sales
revenue (in thousands)
|
$
|
122,335
|
$
|
287,033
|
$
|
(164,698
|
)
|
||||
|
Average
gas sales price per mcf (excluding hedges)
|
$
|
4.15
|
$
|
9.50
|
$
|
(5.35
|
)
|
||||
|
Average
realized gas price per mcf (including hedges)
|
$
|
4.48
|
$
|
9.31
|
$
|
(4.83
|
)
|
||||
|
Decrease
in gas sales revenue due to:
|
|||||||||||
|
Change
in prices (in thousands)
|
$
|
(149,083
|
)
|
||||||||
|
Change
in production volume (in thousands)
|
(15,615
|
)
|
|||||||||
|
Total
decrease in gas sales revenue (in thousands)
|
$
|
(164,698
|
)
|
||||||||
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
||||||||||
|
2009
|
2008
|
||||||||||
|
Total
production (MMcfe)
|
43,782
|
47,332
|
(3,550
|
)
|
|||||||
|
Price per
Mcfe
|
$
|
7.00
|
$
|
11.43
|
$
|
(4.43
|
)
|
||||
|
Oil and Gas
revenue information (in thousands)-
|
|||||||||||
|
Oil and gas
sales revenue
|
$
|
306,308
|
$
|
540,795
|
$
|
(234,487
|
)
|
||||
|
Miscellaneous
revenues(1)
|
$
|
79,030
|
$
|
5,058
|
$
|
73,972
|
|||||
|
(1)
|
Miscellaneous
revenues primarily relate to fees earned under our process handling
agreements. The amount in 2009 also includes $73.5 million of previously
accrued royalty payments involved in a legal dispute that were reversed in
January 2009 following a favorable ruling by the Fifth District Court of
Appeals, which rendered the probability of being required to make this
payments remote. The final resolution of the legal
dispute occurred in October 2009, when the U.S. Supreme Court denied the
plaintiff’s petition for a writ of certiorari. For additional
information regarding the resolution of our royalty dispute See
Item 3. “Legal Proceedings” and Note 6 – Oil and Gas Properties
located elsewhere in this Annual Report on Form
10-K.
|
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 a cost per Mcfe of production
basis (barrels of oil converted to Mcfe at a ratio of one barrel to
six Mcf):
|
Year
Ended December 31,
|
||||||||||||||||
|
2009
|
2008
|
|||||||||||||||
|
Total
|
Per
Mcfe
|
Total
|
Per
Mcfe
|
|||||||||||||
|
Oil and gas
operating expenses(1):
|
||||||||||||||||
|
Direct
operating expenses(2)
|
$ | 78,348 | $ | 1.79 | $ | 81,742 | $ | 1.73 | ||||||||
|
Workover
(3)
|
9,790 | 0.22 | 10,772 | 0.23 | ||||||||||||
|
Transportation
|
8,209 | 0.19 | 5,487 | 0.12 | ||||||||||||
|
Repairs and
maintenance
|
13,469 | 0.31 | 21,032 | 0.44 | ||||||||||||
|
Overhead and
company labor
|
10,020 | 0.23 | 5,521 | 0.12 | ||||||||||||
|
Sub
Total
|
$ | 119,836 | $ | 2.74 | $ | 124,554 | $ | 2.64 | ||||||||
|
Depletion and
amortization
|
$ | 154,052 | $ | 3.52 | $ | 186,038 | $ | 3.93 | ||||||||
|
Abandonment
|
4,369 | 0.10 | 15,985 | 0.34 | ||||||||||||
|
Accretion
|
15,204 | 0.35 | 13,065 | 0.28 | ||||||||||||
|
Impairments (4)
|
69,038 | 1.58 | 181,524 | 3.84 | ||||||||||||
|
Net hurricane (reimbursements)
costs (5)
|
(23,332 | ) | (0.53 | ) | 52,361 | 1.11 | ||||||||||
|
Total
|
$ | 339,167 | $ | 7.76 | $ | 573,527 | $ | 12.14 | ||||||||
|
(1)
|
Excludes
exploration expense of $24.4 million and
$32.9 million for the years ended December 31, 2009
and 2008, respectively. Exploration expense is not a component of lease
operating expense. Also excludes the impairment charge to
goodwill of $704.3 million in fourth quarter of 2008.
|
|
(2)
|
Includes
production taxes.
|
|
(3)
|
Excludes all
hurricane-related costs and charges resulting from Hurricane Ike
in September 2008 (see (5) below).
|
|
(4)
|
Includes
impairment charges for certain oil and gas properties exclusive of
hurricane related charges discussed in (5)
below.
|
|
(5)
|
Amounts
related to damages sustained from Hurricane Ike
in September 2008 (Note 4). Hurricane-related impairments and
adjustments to asset retirement obligations totaled $51.5 million in 2009
and $34.2 million in 2008.
|
Revenues. Our
total revenues decreased by 31% in 2009 as compared to 2008 primarily reflecting
the disposition of our Shelf Contracting business operations in June 2009 (see
“Reduction of Cal Dive Ownership” above and Note 3). Excluding the
effect of removing revenues associated with our former Shelf Contracting
business our total revenues decreased by 16%.
Contracting
Services revenues decreased 17% in 2009 as compared to 2008. The
decrease reflects lower activity levels related to a reduction of services
provided to a customer under a long term construction contract in India as our
pipelay vessel, the Express,
completed its services in the second quarter of 2009. The
Express
departed India for a regulatory drydock in Spain and then redeployed to the Gulf
of Mexico for internal use. Further, we experienced a substantial
reduction in the average day rate realized by our Q4000
vessel deployed as an accommodation vessel in the Gulf of Mexico in the third
quarter of 2009 and an almost complete loss of revenues in our Southeast Asia
well intervention operations caused by equipment repair issues. These
decreases were partially offset by higher results from our robotics subsidiary
and our well operations vessels, including the Q4000 in
the first half of 2009. We experienced strong results throughout the
first half of 2009 but experienced softening in the market as expected over the
second half of 2009. As a result, during the third and
particularly the fourth quarter of 2009 we utilized some of our vessels to
complete work necessary to enhance our oil and gas
operations. This contributed to our decrease in
revenues in 2009 as compared to 2008.
Oil and Gas
revenues decreased by 29% in 2009 as compared to 2008. The decrease
is attributable to significant reductions in the realized prices of both oil
(27%) and natural gas (52%) as compared to amounts realized in
2008. Our production was adversely affected in the third quarter of
2008 as a result of Hurricanes Gustav
and Ike. Although
our production recovered somewhat, production of both oil and natural gas has
continued to be affected by ongoing repairs to third party
pipelines. Repairs to a key third party pipeline were completed in
early January 2010 which should benefit our production as we progress
into 2010 as this particular pipeline provides service to our Noonan gas
reservoir within the Bushwood field where production has been curtailed since it
commenced sustained production in January 2009. Further, our natural
gas derivative contracts for 2009 were marked-to-market and changes in their
fair value were included in “Gain on oil and gas derivative contracts” in the
accompanying consolidated statements of operations rather than revenues as
previously reported when such contracts qualified for hedge accounting
treatment.
Our oil and gas
revenues for the year ended December 31, 2009 benefitted from $73.5 million of
previously accrued royalty payments that were in dispute. Following a
favorable appellate judicial ruling in January 2009, we reversed these amounts
as oil and gas revenues in the first quarter of 2009 and began accounting for
the additional oil and gas revenues associated with the previously disputed
royalty net revenue interest and we are no longer accruing any additional
royalty reserves (Note 6).
Gross
Profit. Gross profit for 2009 decreased $129.0 million as
compared to 2008. Excluding the effect of our former Shelf
Contracting business, our continuing businesses gross profit increased $32.3
million in 2009 as compared to 2008. This increase primarily reflects
reduced year over year impairment charges associated with our Oil and Gas
segment, which totaled $120.6 million in 2009 and $215.7 million in
2008. After considering the reduction in impairment charges our Oil
and Gas segment gross profit decreased by 8% as a result of lower
commodity prices realized and lower natural gas production, as described in
Revenues above, offset partially by the $23.3 million of insurance reimbursement
in excess of hurricane related costs incurred during the year ended December 31,
2009. See Note 6 for a discussion of our oil and gas impairment
charges for 2009 and 2008.
In
addition, Contracting Services gross profit decreased 29% because of the factors
stated above in revenues. Our Contracting Services gross margin decreased by
three points. The decline in gross margin was primarily due to lower
vessel utilization (in particular our pipelay vessels), lower day rates realized
on work performed by the Q4000,
and Express
out of service days related to a regulatory drydock and transit costs to
redeploy the Express
from India back to the Gulf of Mexico for internal use. Most of these
declines occurred in the second half of 2009.
Gain
on Sale of Assets, Net. Gain on sale of assets, net, was $2.0
million in 2009 as compared to a gain of $73.5 million in
2008. The gain on sale in 2008 primarily related to the sale of
a 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506
and 507) and other Outer Continental Shelf oil and gas properties (East Cameron
blocks 371 and 381). Offsetting this gain was a loss of $11.9 million
related to the sale of all our interest in our Onshore
Properties. Included in the cost basis of our Onshore Properties was
$8.1 million of goodwill allocated from our Oil and Gas segment. In
the fourth quarter of 2008 we recorded a $6.7 million loss associated with our
sale of the Bass Lite field as Atwater Block 426.
Selling and
Administrative Expenses. Selling and administrative expenses
totaled $130.9 million in 2009, which was $46.3 million lower than amounts
incurred in 2008. Selling and administrative expenses associated with
our former Shelf Contracting business totaled $33.7 million for the period prior
to its deconsolidation in June 2009 and $74.5 million in
2008.
52
Excluding the selling and
administrative expenses associated with our former Shelf Contracting business,
our selling and administrative expenses decreased $5.5 million in 2009 as
compared to 2008. The decrease in the comparable years reflects $7.4
million of expenses related to the separation agreements between the Company and
two of our former executive officers in 2008 and the enactment of certain
administrative cost saving measures in 2009 offset in part by increased bad debt
expense and legal costs.
Equity
in Earnings of Investments. Equity in earnings of investments
increased by $0.5 million in 2009 as compared to 2008. This increase
primarily reflects $8.1 million related to our approximate 26% ownership
interest in Cal Dive that was accounted for under the equity method accounting
following its deconsolidation in June 2009. The equity in the
earnings for Cal Dive covers the period from June 11, 2009 through September 23,
2009, at which time we sold substantially all our remaining ownership interest
in Cal Dive (Note 3). The remainder of our equity in earnings of
investments included a decrease of $13.2 million in the equity in earnings of
Deepwater Gateway between the comparable years reflecting reduced throughput at
the facility as a result of ongoing hurricane related repairs that have affected
production from the fields processed through the Marco Polo TLP. This
decrease was offset in part by a $2.3 million increase in the earnings of our
20% investment in Independence Hub.
Net
Interest Expense and Other. We reported net interest and other
expense of $51.5 million in 2009 as compared to $111.1 million in
2008. Interest and other expense associated with Cal Dive totaled
$6.6 million prior to deconsolidation in June 2009, while Cal Dive accounted for
$22.3 million of interest and other expense
in 2008. Excluding Cal Dive, gross interest expense
totaling $99.2 million was lower than the $114.5 million incurred in 2008
primarily reflecting lower interest rates and lower levels of debt since year
end 2008. Contributing to the decrease in interest expense was a $6.0
million increase in capitalized interest, which totaled $48.1 million in
2009 and $42.1 million in 2008. We recorded $3.3 million
of unrealized gains associated with mark-to-market adjustments related to our
foreign exchange contracts in 2009 as compared to a net unrealized loss of $1.1
million in 2008. Interest income decreased to $0.9 million in 2009
from $2.4 million in 2008. The decrease in interest income includes a net
reduction of $0.5 million associated with the deconsolidation of Cal
Dive.
Provision
for Income Taxes.
Income taxes increased to $95.8 million in 2009 compared to
$86.8 million in 2008. This increase is primarily due to increased
profitability. The effective tax rate of 36.6% for 2009 was higher than the
(17.6)% for 2008. The effective tax rate for 2008 is not
representative of a normal effective tax rate because of the $704.3 million
non-deductible goodwill and indefinite-lived intangible assets impairment
charge. Excluding the effect of the goodwill and other
intangible asset impairment charges, the effective tax rate would have been
41.2% for 2008. The adjusted effective tax rate decreased as a result of the
deconsolidation of CDI in 2009 and the absence of non-deductible goodwill in the
current year period, which caused an increase in the prior year rate. In 2008,
we allocated $8.1 million of goodwill to the cost basis attributable to certain
sales of oil and gas properties that for income tax purposes was
non-deductible.
Comparison
of Years Ended December 31, 2008 and 2007
The following table
details various financial and operational highlights for the periods
presented:
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
||||||||||
|
2008
|
2007
|
||||||||||
|
Revenues (in
thousands) –
|
|||||||||||
|
Contracting
Services
|
$
|
961,926
|
$
|
673,808
|
$
|
288,118
|
|||||
|
Shelf
Contracting(1)
|
856,906
|
623,615
|
233,291
|
||||||||
|
Oil and
Gas
|
545,853
|
584,563
|
(38,710
|
)
|
|||||||
|
Intercompany
elimination
|
(250,611
|
)
|
(149,566
|
(101,045
|
)
|
||||||
|
$
|
2,114,074
|
$
|
1,732,420
|
$
|
381,654
|
||||||
|
Gross
profit (loss) (in thousands) –
|
|||||||||||
|
Contracting
Services
|
$
|
208,448
|
$
|
187,975
|
$
|
20,473
|
|||||
|
Shelf
Contracting(1)
|
254,007
|
227,398
|
26,609
|
||||||||
|
Oil and
Gas(2)
|
(60,601
|
)
|
120,861
|
(181,462
|
)
|
||||||
|
Corporate
|
(3,652
|
)
|
(7,319
|
3,667
|
|||||||
|
Intercompany
elimination
|
(26,011
|
)
|
(23,008
|
(3,003
|
)
|
||||||
|
$
|
372,191
|
$
|
505,907
|
$
|
(133,716
|
)
|
|||||
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
|||||||||
|
2008
|
2007
|
|||||||||
|
Gross Margin
–
|
||||||||||
|
Contracting
Services
|
22
|
%
|
28
|
%
|
(6
|
)pts
|
||||
|
Shelf
Contracting(1)
|
30
|
%
|
36
|
%
|
(6
|
)pts
|
||||
|
Oil and Gas
(2)
|
(11)
|
%
|
21
|
%
|
(32
|
)pts
|
||||
|
Total
company
|
18
|
%
|
29
|
%
|
(11
|
)pts
|
||||
|
Number of
vessels(3)/
Utilization(4)
–
|
||||||||||
|
Contracting
Services:
|
||||||||||
|
Pipelay
|
9/92
|
%
|
6/79
|
%
|
||||||
|
Well
operations
|
2/70
|
%
|
2/71
|
%
|
||||||
|
ROVs/Trenchers/ROVDrill
Units
|
46/73
|
%
|
39/78
|
%
|
||||||
|
Shelf
Contracting
|
30/60
|
%
|
34/65
|
%
|
||||||
|
1)
|
Represented
by our former majority owned subsidiary, CDI. At
December 31, 2008 and 2007, our ownership interest in CDI was
approximately 57.2% and 58.5%, respectively. See Note 3 for
discussion of transactions in which we sold substantially all our
remaining ownership of CDI in 2009.
|
|
2)
|
Includes
asset impairment charges of oil and gas properties totaling $215.7 million
($192.6 million in fourth quarter of 2008). These impairment
charges do not have any impact on current or future cash
flow.
|
|
3)
|
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.
|
|
4)
|
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, 2008 and 2007 were as
follows (in thousands):
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
|||||||||
|
2008
|
2007
|
|||||||||
|
Contracting Services
|
$
|
195,207
|
$
|
115,864
|
$
|
79,343
|
||||
|
Shelf Contracting
|
55,404
|
33,702
|
21,702
|
|||||||
|
$
|
250,611
|
$
|
149,566
|
$
|
101,045
|
|||||
Intercompany
segment profit (which only relates to intercompany capital projects) during the
years ended December 31, 2008 and 2007 were as follows (in
thousands):
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
||||||||||
|
2008
|
2007
|
||||||||||
|
Contracting Services
|
$
|
20,945
|
$
|
10,026
|
$
|
10,919
|
|||||
|
Shelf Contracting
|
5,066
|
12,982
|
(7,916
|
)
|
|||||||
|
$
|
26,011
|
$
|
23,008
|
$
|
3,003
|
||||||
Revenues
associated with our U.K oil and gas operations totaled $3.9 million in 2008 and
$2.7 million in 2007 on production volumes of 0.3 Bcfe and 0.6 Bcfe,
respectively. The total operating costs associated with our U.K
oil and gas operations totaled $4.1 million in 2008 and $7.3 million
in 2007.
The following table
details various financial and operational highlights related to our Oil and Gas
segment for the periods presented (U.S. operations only as U.K. operations
were immaterial for the periods presented, see above):
|
Year
Ended December 31,
|
Increase/
(Decrease)
|
||||||||||
|
2008
|
2007
|
||||||||||
|
Oil and Gas
information–
|
|||||||||||
|
Oil
production volume (MBbls)
|
2,752
|
3,723
|
(971
|
)
|
|||||||
|
Oil sales
revenue (in thousands)
|
$
|
253,762
|
$
|
251,955
|
$
|
1,807
|
|||||
|
Average
oil sales price per Bbl (excluding hedges)
|
$
|
98.62
|
$
|
70.17
|
$
|
28.45
|
|||||
|
Average
realized oil price per Bbl (including hedges)
|
$
|
92.22
|
$
|
67.68
|
$
|
24.54
|
|||||
|
Increase
(decrease) in oil sales revenue due to:
|
|||||||||||
|
Change
in prices (in thousands)
|
$
|
91,372
|
|||||||||
|
Change
in production volume (in thousands)
|
(89,565
|
)
|
|||||||||
|
Total
increase in oil sales revenue (in thousands)
|
$
|
1,807
|
|||||||||
|
Gas
production volume (MMcf)
|
30,823
|
42,163
|
(11,340
|
)
|
|||||||
|
Gas sales
revenue (in thousands)
|
$
|
287,033
|
$
|
324,282
|
$
|
(37,249
|
)
|
||||
|
Average
gas sales price per mcf (excluding hedges)
|
$
|
9.50
|
$
|
7.46
|
$
|
2.04
|
|||||
|
Average
realized gas price per mcf (including hedges)
|
$
|
9.31
|
$
|
7.69
|
$
|
1.62
|
|||||
|
Increase
(decrease) in gas sales revenue due to:
|
|||||||||||
|
Change
in prices (in thousands)
|
$
|
68,342
|
|||||||||
|
Change
in production volume (in thousands)
|
(105,591
|
)
|
|||||||||
|
Total
decrease in gas sales revenue (in thousands)
|
$
|
(37,249
|
)
|
||||||||
|
Total
production (MMcfe)
|
47,332
|
64,500
|
(17,168
|
)
|
|||||||
|
Price per
Mcfe
|
$
|
11.43
|
$
|
8.93
|
$
|
2.50
|
|||||
|
Oil and Gas
revenue information (in thousands)-
|
|||||||||||
|
Oil and gas
sales revenue
|
$
|
540,795
|
$
|
576,237
|
$
|
(35,442
|
)
|
||||
|
Miscellaneous
revenues(1)
|
$
|
5,058
|
$
|
5,667
|
$
|
(609
|
)
|
||||
|
(1)
|
Miscellaneous revenues
primarily relate to fees earned under our process handling
agreements.
|
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 a cost per Mcfe of production basis
(with barrels of oil converted to Mcfe at a ratio of one barrel to six
Mcf):
|
Year
Ended December 31,
|
||||||||||||||||
|
2008
|
2007
|
|||||||||||||||
|
Total
|
Per
Mcfe
|
Total
|
Per
Mcfe
|
|||||||||||||
|
Oil and gas
operating expenses(1):
|
||||||||||||||||
|
Direct
operating expenses(2)
|
$ | 81,742 | $ | 1.73 | $ | 80,410 | $ | 1.25 | ||||||||
|
Workover
|
10,772 | 0.23 | 11,840 | 0.18 | ||||||||||||
|
Transportation
|
5,487 | 0.12 | 4,560 | 0.07 | ||||||||||||
|
Repairs and
maintenance
|
21,032 | 0.44 | 12,191 | 0.19 | ||||||||||||
|
Overhead and
company labor
|
5,521 | 0.12 | 9,031 | 0.14 | ||||||||||||
|
Subtotal
|
$ | 124,554 | $ | 2.64 | $ | 118,032 | $ | 1.83 | ||||||||
|
Depletion and
amortization
|
$ | 186,038 | $ | 3.93 | $ | 217,382 | $ | 3.37 | ||||||||
|
Abandonment
|
15,985 | 0.34 | 21,073 | 0.33 | ||||||||||||
|
Accretion
|
13,065 | 0.28 | 10,701 | 0.17 | ||||||||||||
|
Impairments (3)
|
181,524 | 3.84 | 64,072 | 0.99 | ||||||||||||
|
Net hurricane costs
|
52,361 | 1.11 |
─
|
─
|
||||||||||||
|
Total
|
$ | 573,527 | $ | 12.14 | $ | 431,260 | $ | 6.69 | ||||||||
|
(1)
|
Excludes
exploration expense of $32.9 million and $26.7 million for the
years ended December 31, 2008 and 2007, respectively. Exploration
expense is not a component of lease operating expense. Also
excludes the impairment charge to goodwill of $704.3 million in fourth
quarter of 2008.
|
|
(2)
|
Includes
production taxes.
|
|
(3)
|
Includes
impairment charges for certain oil and gas properties exclusive of
hurricane related impairment charges in (4) below.
|
|
(4)
|
Reflects
costs associated with hurricane damages caused by Hurricane Ike in
September 2008. Amount includes property impairment
charges related to the hurricane of $34.2 million. See
Note 4 for additional information related to our hurricane costs and
subsequent insurance recoveries related to Hurricane
Ike.
|
Revenues. During
the year ended December 31, 2008 our consolidated net revenues increased by
22% compared to 2007. Contracting Services gross revenues increased 43% over
2007 amounts primarily reflecting the following:
|
•
|
the addition
of two chartered subsea construction vessels as well as an overall
increase in utilization of our subsea construction
vessels;
|
||
|
•
|
commencing
performance of several longer term contracts;
|
||
|
•
|
increases in
the utilization and rates realized for our well operations
vessels;
|
||
|
•
|
strong
performance by our robotics division driven by a higher number of ROVs in
our fleet and additional services required following Hurricanes Gustav
and Ike;
and
|
||
|
•
|
increased
sales by our Shelf Contracting business (see below), resulting from its
acquisition of Horizon in December 2007 and increased work
following Hurricanes Gustav
and Ike.
|
Our increases were
partially offset by the following negative factors:
|
•
|
an increase
in the number of out-of-service days for the Q4000
associated with marine and drilling upgrades. The
Q4000
was out of service for most of the first half of 2008;
|
||
|
•
|
weather related downtime
associated with Hurricanes Gustav
and Ike.
|
Gross revenues for
our Shelf Contracting business increased 37% in 2008 compared to 2007 primarily
reflecting the revenue contribution of the Horizon assets that were acquired in
December 2007 partially offset by lower vessel utilization related to winter
seasonality and harsh weather conditions which continued into May 2008, and
weather downtime associated with Hurricanes Gustav
and Ike.
Following the storm, our Shelf Contracting revenues benefitted from the
increased scope of work associated with the storms
including inspections, repairs and reclamation projects.
Oil and Gas
revenues decreased 7% during 2008 as compared to the prior year. The decrease is
primarily associated with the loss of production following the shut-in of many
of our oil and gas properties following Hurricanes Gustav
and Ike.
Our production rates in 2008 were 27% lower than the same period last
year; however our current net daily production is approximately 90% of pre-storm
production volumes after adjusting for the sale of one major deepwater property
in December 2008. The decrease in our revenues was partially
offset by substantially higher oil and natural gas prices realized over the
amounts received in 2007, which reflects near historical high prices for both
oil and natural gas over the first half of 2008. Prices of both oil
and natural gas decreased significantly during the second half of 2008, with
price reductions accelerating in the fourth quarter of 2008.
Gross
Profit. The Contracting Services gross profit increase was
primarily attributable to improved contract pricing for the well operations and
ROV divisions. These increases were partially offset by lower margins realized
on certain longer term deepwater pipelay projects reflecting the
delays in delivery of the Caesar
and processing of certain change orders which prevented revenue recognition
under the percentage-of-completion method (Note 2). We also recorded
approximately $9.8 million of estimated losses on two contracts in which we
believe the future revenue benefits will be exceeded by the estimated future
costs to service the contracts (Note 2). The gross profit
increase within Shelf Contracting was primarily attributable to the initial
deployment of Horizon’s assets that were acquired in December 2007 and
additional work following Hurricanes Gustav
and Ike,
offset by increased depreciation associated with Horizon assets and
weather-related delays over the first five months of 2008 and during Hurricanes
Gustav
and Ike. Our
2007 Shelf Contracting operations were adversely effected by an higher number of
out-of-service days referred to above, lower vessel
56
utilization as a result of seasonal
weather in the fourth quarter 2007, and increased depreciation and deferred
drydock amortization.
The decrease in the
gross profit for our oil and gas operations in 2008 as compared to 2007 reflects
the following key factors :
|
•
|
impairment
expense of approximately $215.7 million ($192.6 million recorded in the
fourth quarter of 2008) related to our proved oil and gas properties
primarily as a result of downward reserve revisions reflecting lower oil
and natural gas prices, weak end of life well performance for some of our
domestic properties, fields lost as a result of Hurricanes Gustav
and Ike
and the reassessment of the economics of some of our marginal fields in
light of our announced business strategy to exit the oil and gas
exploration and production business; we also recorded a $14.6
million asset impairment charge associated with the Devil’s Island
Development well (Garden Banks Block 344) that was determined to be
non-commercial in January 2008. Asset impairment expense
in 2007 totaled $64.1 million, which included $20.9 million for the costs
incurred on the Devil’s Island well through December 31,
2007;
|
||
|
•
|
a decrease of
$31.3 million in depletion expense in 2008 because
of lower production which is primarily attributed to the
effects Hurricanes Gustav
and Ike
had on our production during the latter part of the year. This
decrease was partially offset by higher rates resulting from a reduction
in estimated proved reserves for a number of our producing fields at
December 31, 2008;
|
||
|
•
|
approximately
$8.8 million of exploration expense (all in fourth quarter of 2008)
compared to $9.0 million in 2007 related to reducing the
carrying value of our unproved properties primarily due to management’s
assessment that exploration activities for certain properties will not
commence prior to the respective lease expiration
dates;
|
||
|
•
|
approximately
$16.0 million of plug and abandonment overruns primarily related to
properties damaged by the hurricanes, partially offset by insurance
recoveries of $7.8 million; and
|
||
|
•
|
approximately
$18.8 million of dry hole exploration expense reflecting the conclusion
that two exploratory wells previously classified as suspended wells (Note
6) no longer met the requirements to continue to be capitalized primarily
as a result of the discontinuing of plans to progress the development of
these wells in light of our announcement in December 2008 of our intention
to pursue a sale of all or a portion of our oil and gas
assets. In 2007, our dry hole expense totaled $10.3
million, of which $5.9 million was related to our South Marsh Island Block
123 #1 well.
|
Goodwill
and other intangible asset impairments. In the fourth quarter
of 2008 we recorded a $704.3 million of impairment charge to write off the
remaining oil and gas goodwill following our annual assessment of goodwill,
which took into account the significant decrease in our common stock price as
well as the stock prices of our identified peers and the rapid reduction in oil
and natural gas commodity prices. We also recorded an $8.3 million
impairment charge in the fourth quarter of 2008 to write off the goodwill
associated with our 2005 acquisition of Helix Energy Limited as well as a
related $2.4 million impairment charge to write off its indefinite life asset
(trademark). These amounts are reflected as a component of income (loss) from
discontinued operations in the accompanying consolidated statement of operations
as Helix Energy Limited was sold in April 2009. We separately
recorded $8.1 million of reductions of goodwill associated with dispositions of
oil and gas properties in 2008, which are included as a component of the gain or
loss on sale of assets, net as discussed below.
Gain
on Sale of Assets, Net. The net gain on sale of assets
increased by $23.1 million during 2008 as compared to 2007. In 2008 our oil
and gas property sales included:
|
•
|
$91.6 million
gain related to the sale of a 30% working interest in the Bushwood
discoveries (Garden Banks Blocks 463, 506 and 507) and East Cameron Blocks
371 and 381;
|
||
|
•
|
$11.9 million
loss related to the sale of all our onshore properties; included in the
cost basis of our onshore properties was goodwill of $8.1 million;
and
|
||
|
•
|
$6.7 million
loss related to the sale of our interest in the Bass Lite field in
December 2008; there was no goodwill associated with this sale as all
goodwill was previously written off. The sale of the remainder
(approximately 10%) of our original 17.5% interest closed in January 2009
and will be reflected in our first-quarter 2009
results.
|
On
September 30, 2007, we sold a 30% working interest in the Phoenix oilfield
(Green Canyon Blocks 236/237), the Boris oilfield (Green Canyon
Block 282) and the Little Burn oilfield (Green Canyon
Block 238) to Sojitz GOM Deepwater, Inc. (“Sojitz”) for a cash payment
of $51.2 million and recognized a gain of $40.4 million in 2007. We
also recognized the following gains in 2007:
|
•
|
$2.4 million
related to the sale of a mobile offshore production
unit;
|
||
|
•
|
$1.6 million
related to the sale of 50% interest in Camelot, which is located offshore
of United Kingdom; and
|
||
|
•
|
$3.9 million
related to the sale of assets owned by
CDI.
|
Selling
and Administrative Expenses. Selling and administrative
expenses of $177.2 million in 2008 were $32.2 million higher than the
$145.0 million incurred in 2007. The increase was due primarily to higher
overhead (primarily related to CDI’s Horizon acquisition) to support our
growth. We also recognized approximately $7.4 million of expenses
related to the separation agreements between the Company and two of its former
executive officers (Note 21). Selling and administrative expenses as a percent
of revenues were approximately 8.4% for both 2008 and 2007.
Equity
in Earnings of Investments, Net of Impairment Charge. Equity
in earnings of investments increased $12.3 million during 2008 as compared
to 2007. Equity in earnings related to our 20% investment in Independence Hub
increased $9.3 million as we reached mechanical completion in March 2007
and began receiving demand fees and tariffs as production began in the third
quarter of 2007. In addition, equity in earnings of our 50% investment in
Deepwater Gateway decreased by $3.5 million in 2008 as compared to 2007 due
to downtime at the Marco
Polo
TLP following Hurricanes Gustav
and Ike.
These increases were offset by second quarter 2007 equity losses from CDI’s 40%
investment in Offshore Technology Solutions Limited (“OTSL”) and a related
non-cash asset impairment charge together totaling
$11.8 million.
Net
Interest Expense and Other. Net interest and other expense
increased to $89.5 million in 2008 as compared to $67.0 million in the
prior year. Gross interest expense of $137 million during 2008 was higher
than the $107.8 million incurred in 2007 because of higher levels of
indebtedness as a result of our Senior Unsecured Notes and CDI’s term
loan, both of which closed in December 2007. Offsetting the increase
in interest expense was $42.1 million of capitalized interest and
$2.4 million of interest income in 2008, compared with $31.8 million
of capitalized interest and $9.2 million of interest income in 2007. We
expect interest expense to decrease in 2009 as a result of lower expected
interest rates on our variable rate debt instruments.
See Note 10 for detailed description of these
notes. Our other income (expense) includes gains (losses) associated
with transactions denominated in foreign currencies. Our foreign
currency losses totaled $(10.0) million in 2008 and $(0.5) million in
2007.
Provision
for Income Taxes. Income
taxes decreased to $86.8 million in 2008 compared to $171.9 million in
2007. This decrease is primarily due to lower profitability in 2008. The
effective tax rate of (17.6)% is not representative of a normal effective tax
rate because of the $704.3 million non-deductible goodwill and indefinite-lived
intangible assets impairment charge as discussed above.
Excluding the goodwill and other intangible asset impairment charges, the
effective tax rate of 41.2% for 2008 was higher than the 33.3% effective tax
rate for same period 2007 primarily reflecting the additional deferred tax
expense recorded as a result of the increase in the equity earnings of CDI in
excess of our tax basis. In 2008, we allocated $8.1 million of goodwill to the
cost basis attributable to certain sales of oil and gas properties that for
income tax purposes was non-deductible.
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):
|
2009
|
2008
|
|||||||
|
Net working capital
|
$
|
197,072
|
$
|
287,225
|
||||
|
Long-term debt(1)
|
$
|
1,348,315
|
$
|
1,933,686
|
|
(1)
|
Long-term
debt does not include current maturities portion of the long-term debt as
amount is included in net working
capital.
|
The carrying amount
of our debt, including current maturities as of December 31, 2009 and 2008
follow (amount in thousands):
|
2009
|
2008
|
|||||
|
Term Loan (matures July
2013)
|
$
|
414,766
|
$
|
419,093
|
||
|
Revolving Credit Facility
(matures November 2012)
|
─
|
349,500
|
||||
|
Convertible Senior Notes
(matures March 2025)
(1)
|
273,064
|
265,184
|
||||
|
Senior Unsecured Notes
(matures January 2016)
|
550,000
|
550,000
|
||||
|
MARAD Debt (matures August
2027)
|
119,235
|
123,449
|
||||
|
Cal Dive Term Loan (2)
|
─
|
315,000
|
||||
|
Loan Notes(3)
|
3,674
|
5,000
|
||||
|
Total
|
$
|
1,360,739
|
$
|
2,027,226
|
||
|
(1)
|
Net of the
unamortized debt discount resulting from adoption of FSP APB 14-1 on
January 1, 2009. The notes will increase to $300 million
face amount through accretion of non-cash interest charges through
2012.
|
|
(2)
|
We
deconsolidated Cal Dive from our financial statements in June 2009 (Note
3).
|
|
(3)
|
Assumed to be
current, represents the loan provided by Kommandor RØMØ to Kommandor LLC
(Note 9).
|
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net cash
provided by (used in):
|
||||||||||||
|
Operating
activities
|
$
|
415,547
|
$
|
437,719
|
$
|
416,326
|
||||||
|
Investing
activities
|
$
|
(68,532
|
)
|
$
|
(557,974
|
)
|
$
|
(739,654
|
)
|
|||
|
Financing
activities
|
$
|
(298,579
|
)
|
$
|
256,216
|
$
|
206,445
|
|||||
Our current
requirements for cash primarily reflect the need to fund capital expenditures to
allow the growth of our current lines of business and to service our existing
debt. We also intend to repay debt with any additional free cash flow
from operations and/or cash received from any dispositions of our non core
business assets. Historically, we have funded our capital program,
including acquisitions, with cash flow from operations, borrowings under credit
facilities and use of project financing along with other debt and equity
alternatives.
We
continue to focus on improving our balance sheet by increasing our liquidity
through reductions in planned capital spending and potential additional
dispositions of our non-core business assets. We also have a
reasonable basis for estimating our future cash flow supported by our remaining
Contracting Services backlog and the significant hedged portion of our estimated
oil and gas production for 2010. We believe that internally generated
cash flow and available borrowing capacity under our amended Revolving Credit
Facility (see “Amendment of Senior Credit Facility” below and Note 10) will be
sufficient to fund our operations over at least the next twelve
months. In the first half of 2009, we repaid all remaining borrowings
under our revolving credit facility, which totaled $349.5 million.
During 2009, we
completed the following transactions related to dispositions of non-core
business assets:
|
·
|
Sold five oil
and gas properties for approximately $24
million;
|
|
·
|
Sold a total
of 15.2 million shares of CDI common stock held by us to CDI for $100
million in separate transactions in January and June
2009;
|
|
·
|
Sold Helix
RDS Limited, our subsurface reservoir consulting business for $25 million
in April 2009; and
|
|
·
|
Sold a total
of 45.8 million shares of CDI common stock held by us to third parties in
two separate public secondary offerings for approximately $404.4 million,
net of underwriting fees in June 2009 and September 2009. For
additional information regarding the sales of CDI common shares by us see
“Reduction of Cal Dive Ownership” above and Note
3.
|
Some of the
significant financings and corresponding uses were as follows:
|
•
|
In July 2007,
we purchased the remaining 42% of WOSEA for $10.1 million. We now own
100% of this company (see “Note 5 —Acquisitions” in Item 8.
Financial
Statements and Supplementary Data for a detailed discussion of
WOSEA).
|
||
|
•
|
In December 2007, we issued
$550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior
Unsecured Notes”). Proceeds from the offering were used to repay
outstanding indebtedness under our senior secured credit facilities. For
additional information on the terms of the Senior Unsecured Notes, see
“Note 10 — Long-term Debt” in Item 8.
Financial Statements and Supplementary Data.
|
||
|
•
|
In July 2006,
we borrowed $835 million in a term loan (“Term Loan”) and entered
into a new $300 million revolving credit facility (Note 10). The
proceeds of the Term Loan were used to fund the cash portion of the
acquisition of Remington. We also issued approximately 13.0 million
shares of our common stock to the Remington
shareholders.
|
||
|
•
|
In December
2006, we completed an IPO of our Shelf Contracting business segment
(Cal Dive), selling 26.5% of that company and receiving pre-tax net
proceeds of $264.4 million (Note 3). Proceeds from the offering were
used for general corporate purposes, including the repayment of
$71.0 million of borrowing under our Revolving Credit Facility (Note
10).
|
||
|
•
|
In October
2006, we initially invested $15 million for a 50% interest in
Kommandor LLC, 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 LLC (Note 9). We
named the vessel the Helix
Producer I.
|
||
|
•
|
Also in
October 2006, we acquired the original 58% interest in WOSEA 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 WOSEA shares
(Note 5).
|
In
accordance with our Senior Credit Facilities, Senior Unsecured Notes, the
Convertible Senior Notes and the MARAD debt, we are required to comply with
certain covenants and restrictions, including certain financial ratios such as
collateral coverage, interest coverage, consolidated leverage, the maintenance
of minimum net worth, working capital and debt-to-equity requirements. As of
December 31, 2009, we were in compliance with these covenants. The Senior
Credit Facilities and Senior Unsecured Notes 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 permit
us to incur certain unsecured indebtedness, and also provide for our
subsidiaries to incur project financing indebtedness (such as our MARAD loans)
secured by the underlying asset, provided that the indebtedness is not
guaranteed by us. Upon the occurrence of certain dispositions or the issuance or
incurrence of certain types of indebtedness, we may be required to prepay a
portion of the Term Loan equal to the amount of proceeds received from such
occurrences. Such prepayments will be applied first to the Term Loan, and any
excess will then be applied to the Revolving Loans.
A
prolonged period of weak economic activity may make it difficult to comply with
our covenants and other restrictions in agreements governing our
debt. Our ability to comply with these covenants and other
restrictions is affected by the continued weak economic conditions and other
events beyond our control. If we fail to comply with these covenants
and other restrictions, it could lead to an event of default, the possible
acceleration of our repayment of outstanding debt and the exercise of certain
remedies by the lenders, including foreclosure on our pledged
collateral.
As
of December 31, 2009, our liquidity totaled $656.5 million, including cash
of $270.7 million and $385.8 million of available borrowing capacity
under our Revolving Credit Facility. As of February 23, 2010 our
liquidity totals approximately $591.3 million, including $205.8 million of cash
and cash equivalents and $385.5 million of available borrowing capacity under
our Revolving Credit Facility.
We
amended our Senior Credit Facility in October 2009 and again in February
2010. In October 2009 the Senior Credit Facility was amended to,
among other things, extend its maturity from July 2011 to November
2012. In February 2010, the Senior Credit Facility was once
again amended, to among other things, modify the consolidated leverage ratio
test and to include an additional senior secured debt leverage ratio
test for periods beginning on or after March 31, 2010. See Note 10
for additional information related to our long-term debt, including more
information regarding the recent amendments of our Senior Credit Facility and
our requirements and obligations under the debt agreements including our
covenants and collateral security.
Working
Capital
Net cash flows from
operating activities decreased $22.2 million in 2009 as compared to 2008
primarily reflecting significantly lower revenues, which were mostly offset by
an increase in our working capital cash flow, including lower income
taxes paid and higher amounts collected on our accounts receivable
balances.
Net cash flows from
operating activities increased $21.4 million in 2008 as compared to 2007
primarily reflecting significantly lower income taxes paid and increased gross
profit from Contracting Services and Shelf Contracting businesses.
These increases were partially offset by lower operating results for our Oil and
Gas business reflecting the effects of Hurricanes Gustav
and Ike
had on its production during the third and fourth quarters of 2008 as well as
our increased funding of our working capital requirements.
Investing
Activities
Capital
expenditures have consisted principally of 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, 2009, 2008 and 2007
were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Capital
expenditures:
|
||||||||||||
|
Contracting
services
|
$ | (204,228 | ) | $ | (258,184 | ) | $ | (286,362 | ) | |||
|
Shelf
contracting
|
(39,569 | ) | (83,108 | ) | (30,301 | ) | ||||||
|
Oil
and
gas
|
(137,168 | ) | (404,308 | ) | (519,632 | ) | ||||||
|
Production
facilities
|
(42,408 | ) | (109,454 | ) | (106,086 | ) | ||||||
|
Acquisition
of businesses, net of cash acquired:
|
||||||||||||
|
Horizon
Offshore Inc.
(1)
|
─
|
─
|
(137,431 | ) | ||||||||
|
WOSEA(2)
|
─
|
─
|
(10,067 | ) | ||||||||
|
Sales of
short-term
investments
|
─
|
─
|
285,395 | |||||||||
|
Investments
in production
facilities
|
(1,657 | ) | (846 | ) | (17,459 | ) | ||||||
|
Distributions from equity
investments, net(3)
|
6,742 | 11,586 | 6,679 | |||||||||
|
Proceeds from
insurance
reimbursements
|
─
|
13,200 |
─
|
|||||||||
|
Proceeds from
sale of Cal Dive common stock
|
418,168 |
─
|
─
|
|||||||||
|
Reduction in
cash from deconsolidation of Cal Dive
|
(112,995 | ) |
─
|
─
|
||||||||
|
Proceeds from
sale of properties (4)
|
23,717 | 274,230 | 78,073 | |||||||||
|
Other,
net
|
(6 | ) | (614 | ) | (1,248 | ) | ||||||
|
Net
cash used in investing
activities
|
(89,404 | ) | (557,498 | ) | (738,439 | ) | ||||||
|
Net
cash provided by (used in)discontinued operations(5)
|
20,872 | (476 | ) | (1,215 | ) | |||||||
|
Net
cash used in investing
activities
|
$ | (68,532 | ) | $ | (557,974 | ) | $ | (739,654 | ) | |||
|
(1)
|
Acquisition
by our former majority owned subsidiary, CDI (Note 3).
|
|
(2)
|
For
additional information related to these acquisitions, see Note
5.
|
|
(3)
|
Distributions
from equity investments is net of undistributed equity earnings from our
investments. Gross distributions from our equity investments are detailed
in Note 8.
|
|
(4)
|
For
additional information related to sales of properties, see Note
6.
|
|
(5)
|
Amount for
2009 included the sale of Helix RDS for $25 million, see Note
1.
|
Restricted
Cash
As
of December 31, 2009 and 2008 we had $35.4 million of restricted cash,
included in other assets, net, in the accompanying consolidated balance sheet,
all of which related to the escrow funds for decommissioning liabilities
associated with the South Marsh Island Block 130 (“SMI 130”) acquisition in
2002. Under the purchase agreement for this property, we are obligated to escrow
50% of production up to the first $20 million and 37.5% of production on
the remaining
61
balance
up to $33 million in total. We had fully escrowed the
requirement as of December 31, 2009 and 2008. We may use the restricted
cash for decommissioning the related field.
Outlook
We
anticipate capital expenditures in 2010 will total approximately $200
million. The estimates for these capital expenditures may increase or
decrease based on various economic factors. However, we may
reduce the level of our planned capital expenditures given a
prolonged economic downturn or inability to execute sales transactions related
to our non core business assets. We believe internally generated cash
flow, cash from future sales of our non-core business assets, and borrowings
under our existing credit facilities will provide the capital necessary to fund
our 2010 initiatives.
Contractual
Obligations and Commercial Commitments
The following table
summarizes our contractual cash obligations as of December 31, 2009 and the
scheduled years in which the obligation are contractually due (in
thousands):
|
Total (1)
|
Less
Than 1 year
|
1-3
Years
|
3-5
Years
|
More
Than 5 Years
|
||||||||||||||||
|
Convertible
Senior Notes(2)
|
$
|
300,000
|
$
|
─
|
$
|
─
|
$
|
─
|
$
|
300,000
|
||||||||||
|
Senior
Unsecured
Notes
|
550,000
|
─
|
─
|
─
|
550,000
|
|||||||||||||||
|
Term
Loan
|
414,766
|
4,326
|
8,652
|
401,788
|
─
|
|||||||||||||||
|
Revolving
Loans
|
─
|
─
|
─
|
─
|
─
|
|||||||||||||||
|
MARAD
debt
|
119,235
|
4,424
|
9,522
|
10,496
|
94,793
|
|||||||||||||||
|
Loan
note
|
3,674
|
3,674
|
─
|
─
|
─
|
|||||||||||||||
|
Interest
related to long-term debt
|
563,436
|
79,924
|
155,906
|
140,008
|
187,598
|
|||||||||||||||
|
Drilling and
development costs
|
58,717
|
58,717
|
─
|
─
|
─
|
|||||||||||||||
|
Property and
equipment(4)
|
14,854
|
14,854
|
─
|
─
|
─
|
|||||||||||||||
|
Operating
leases(5)
|
99,110
|
43,781
|
51,611
|
2,922
|
796
|
|||||||||||||||
|
Total cash
obligations
|
$
|
2,123,792
|
$
|
209,700
|
$
|
225,691
|
$
|
555,214
|
$
|
1,133,187
|
|
(1)
|
Excludes
unsecured letters of credit outstanding at December 31, 2009 totaling
$49.2 million. These letters of credit primarily guarantee various
contract bidding, insurance activities and shipyard
commitments.
|
|
(2)
|
Contractual
maturity in 2025 (Notes can be redeemed by us or we may be required to
purchase beginning in December 2012). Notes can be converted prior to
stated maturity if the closing sale price of Helix’s 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, 2009, the conversion
trigger was not met.
|
|
(3)
|
Any future
borrowing under our Revolver will mature on November 30,
2012.
|
|
(4)
|
Costs
incurred as of December 31, 2009 and additional property and
equipment commitments (excluding capitalized interest) at
December 31, 2009 consisted of the following (in
thousands):
|
|
Costs
Incurred (a)
|
Costs
Committed
|
Total
Project
Cost (a)
|
||||||||||
|
Caesar conversion
|
$
|
264,777
|
$
|
2,288
|
$
|
290,000—300,000
|
||||||
|
Well Enhancer
construction
|
232,612
|
486
|
250,000—260,000
|
|||||||||
|
Helix Producer I
conversion(b)
|
269,449
|
12,080
|
360,000—370,000
|
|||||||||
|
Total
|
$
|
766,838
|
$
|
14,854
|
$
|
900,000—930,000
|
|
(a)
|
Includes
capitalized interest.
|
|
(b)
|
Represents 100% of the vessel
conversion cost, of which we expect our portion to range between
$318 million and $328 million.
|
|
(5)
|
Operating
leases include facility leases and vessel charter leases. Vessel charter
lease commitments at December 31, 2009 were approximately
$84.9 million.
|
Contingencies
As
disclosed in Notes 6 and 17, litigation involving the MMS claim that royalties
were owed with respect to the oil and natural gas leases comprising our Gunnison
deepwater field at Garden Banks Blocks 667, 668 and 669 was concluded in October
2009 with no change in our previous conclusion on the issue.
In
January 2009, following the decision of the United States Court of Appeals for
the Fifth Circuit Court to affirm the decision of the district court, we
reversed our previously accrued royalties ($73.5 million) as oil and gas revenue
in our first quarter 2009 results. Also effective in January 2009, we commenced
recognizing oil and natural gas sales revenue associated with this previously
disputed net revenue interest and we are no longer accruing any additional
royalty reserves as we believe it is remote that we will be liable for such
amounts.
A
number of our longer term pipelay contracts have been adversely affected by
delays in the completion and delivery of the
Caesar. We believe two of our contracts qualify as loss
contracts as defined under SOP 81-1 “Accounting
for Performance of Construction-Type and Certain Production-Type
Contracts”. Accordingly, we have estimated the future
shortfall between our anticipated future revenues versus future
costs. For one contract that was completed in May 2009, our loss was
$0.8 million, all of which was provided with our estimated loss accrual at
December 31, 2008. Under a second contract, which was terminated, we
have a potential future liability of up to $25 million. As of
December 31, 2008, we estimated the loss under this contract at $9.0
million. In the second quarter of 2009, services under this contract
were substantially completed and we revised our estimated loss to approximately
$15.8 million. To reflect this additional estimated loss we recorded
an additional $6.8 million charge to cost of sales in the accompanying condensed
consolidated statement of operations. We recently agreed to
settle our obligation under this contract for $12.7
million. Accordingly we reversed $3.1 million of our previously
accrued costs under this contract to reduce it from the estimated $15.8 million
loss to $12.7 million at December 31, 2009. We have paid
$7.2 million of the $12.7 million of estimated damages related to this
terminated contact and expect to pay the remaining $5.5 million in the second
quarter of 2010.
In March
2009, we were notified of a third party’s intention to terminate an
international construction contract based on a claimed breach of that contract
by one of our subsidiaries. As there are substantial defenses to this
claimed breach, we cannot at this time determine if we have
any exposure under the contract. In 2010, we will
continue to assess our potential exposure to damages under this contract as the
circumstances warrant. Under the terms of the contract, our potential
liability is generally capped for actual damages at approximately $27
million Australian dollars (“AUD”) (approximately $24.3 million US dollars at
December 31, 2009) and for liquidated damages at approximately $5
million AUD (approximately $4.5 million US dollars at December 31, 2009).
At December 31, 2009, we have a $4.0 million AUD (approximately $3.6 million US
dollars at December 31, 2009) receivable against our counterparty for work
performed prior to the termination of the contract. We continue to
pursue payment for this work and other claims against our counterparty. We have
filed a counterclaim that in the aggregate approximates $12.0 million U.S.
dollars. See Item 3. Legal
Proceedings and Notes 6 and 17 for a detailed discussion of this
contingency.
Convertible
Preferred Stock
In
January 2003, we completed the private placement of $25 million of a newly
designated class of cumulative convertible stock (Series A-1 Cumulative
Convertible Preferred Stock, par value $0.01 per share) convertible into
1,666,668 shares of our common stock at $15 per share. The preferred
stock was issued to a private investment firm, Fletcher International, Ltd.
(“Fletcher”). Subsequently on June 2004, Fletcher exercised an
existing right to purchase an additional $30 million of cumulative convertible
preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value
$0.01 per share) convertible into 1,964,058 shares of our common stock at $15.27
per share. Pursuant to the agreement governing the preferred stock
(the “Fletcher Agreement”), Fletcher was entitled to convert the preferred
shares into common stock at any time, and to redeem the preferred shares into
common stock at any time after December 31, 2004. In January 2009,
Fletcher issued a redemption notice with respect to all its shares of the Series
A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we
issued and delivered 5,938,776 shares of our common stock to Fletcher based on a
redemption price of $5.05 per share as determined by the average closing price
of our common stock on the three days starting on the third day prior to holder
redeeming the shares of Series A-2 Cumulative Preferred
Stock. Accordingly, in the first quarter of 2009 we recognized a
$29.3 million charge to reflect the terms of this redemption, which was recorded
as a reduction to our net income applicable to common
shareholders. This beneficial conversion charge reflected the value
associated with the additional 3,974,718 shares redeemed over the original
63
1,964,058 shares
that were contractually required to be issued upon conversion but was limited to
the $29.3 million of net proceeds we received from the issuance of the Series
A-2 Cumulative Convertible Preferred Stock.
The Fletcher
Agreement provides that if the volume weighted average price of our common stock
on any date is less than a certain minimum price (calculated at $2.767
subsequent to the above described redemption), then our right to pay Fletcher
dividends in our common stock is extinguished, and we are required to deliver a
notice to Fletcher that either (1) the conversion price will be reset to such
minimum price (in which case Fletcher shall have no further right to cause the
redemption of the preferred stock), or (2) in the event Fletcher exercises its
redemption rights, we will satisfy our redemption obligations either in cash, or
a combination of cash and common stock subject to a maximum number of shares
(14,973,814) that can be delivered to Fletcher under the Fletcher
Agreement. On February 25, 2009, the volume weighted average price of our
common stock was below the minimum price, and on February 27, 2009 we provided
notice to Fletcher that with respect to the Series A-1 Cumulative Convertible
Preferred Stock the conversion price is reset to $2.767 as of that date and that
Fletcher shall have no further rights to redeem the shares, and we have no
further right to pay dividends in common stock. Subsequent to this election, the
conversion price is not subject to any further adjustment or
reset. As a result of the reset of the conversion price, Fletcher was
entitled to receive an aggregate of 9,035,056 shares in future conversion(s)
into our common stock based on the fixed $2.767 conversion price. In the event
we elect to settle any future conversion in cash, Fletcher would receive cash in
an amount approximately equal to the value of the shares it would receive upon a
conversion, which could be substantially greater than the original face amount
of the Series A-1 Cumulative Convertible Preferred Stock, and which would result
in additional beneficial conversion charges in our statement of operations.
Under the existing terms of our Senior Credit Facilities we are not permitted to
deliver cash to the holder upon a conversion of the Convertible Preferred
Stock.
In
connection with the reset of the conversion price of the Series A-1 Cumulative
Convertible Preferred Stock to $2.767, we were required to recognize a $24.1
million charge to reflect the value associated with the additional 7,368,388
shares that will be required to be delivered upon any future conversion(s) over
the 1,666,668 shares that were to be delivered under the original contractual
terms. This $24.1 million charge was recorded as a beneficial
conversion charge reducing our net income applicable to common
shareholders. Similar to the beneficial conversion charge associated
with the redemption of Series A-2 Cumulative Convertible Preferred Stock, the
beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred
Stock is limited to the $24.1 million of net proceeds received upon its
issuance.
On
July 23, 2009 and August 12, 2009, Fletcher provided a notice of conversion
informing us of its election to convert 15,000 shares and 4,000 shares,
respectively, of the Series A-1 Cumulative Convertible Preferred Stock into
5,421,033 shares and 1,445,608 shares, respectively, of our common
stock. In connection with the closing of each of these conversions we also
paid the accrued and unpaid dividends associated with these shares in cash, the
amount of which was immaterial at the time of the conversion
notice. The conversions were consummated on July 27, 2009 and
August 14, 2009, respectively.
At
December 31, 2009, we had 6,000 shares of convertible preferred stock
outstanding, which are convertible into 2,168,413 shares of our common
stock. The convertible preferred stock maintains its mezzanine
presentation below liabilities but is not included as component of shareholders’
equity, because we may, under certain instances, be required to settle any
future conversions in cash.
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 (Note 2).
Revenue
Recognition
Contracting
Services Revenues
Revenues from
Contracting Services and Shelf Contracting are derived from contracts that
traditionally have been of relatively short duration; however, beginning in
2007, contract durations started to become long-term. 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. Further, we record revenue net of taxes collected from
customers and remitted to governmental authorities.
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, 2009 and 2008 are expected to be billed and collected within
one year.
Dayrate
Contracts. 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.
Turnkey
Contracts. 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 project’s 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. At December 31, 2008, we had two contracts that were
deemed to be in loss status and we recorded an aggregate $9.8 million charge to
cost of sales to estimate the expected loss to completion of the respective
contracts (Note 2). We recognize additional contract revenue related
to claims when the claim is probable and legally enforceable.
Oil
and Gas Revenues
We
record revenues from the sales of crude oil and natural gas when delivery to the
customer has occurred, prices are fixed and determinable, collection is
reasonably assured 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
65
of
December 31, 2009, the net imbalance was a $2.5 million asset and was
included in Other Current Assets ($7.6 million) and Accrued Liabilities
($5.1 million) in the accompanying consolidated balance
sheet.
Goodwill
and Other Intangible Assets
Under Codification
or (“ASC”) Topic No. 350
“Intangibles
– Goodwill and Other”, we are required to perform an annual impairment
analysis of goodwill and intangible assets. We elected November 1 to
be the annual impairment assessment date for goodwill and other intangible
assets. However, we could be required to evaluate the recoverability
of goodwill and other intangible assets prior to the required annual assessment
date if we experience disruption to the business, unexpected significant
declines in operating results, divestiture of a significant component of the
business, emergence of unanticipated competition, loss of key personnel or a
sustained decline in market capitalization. ASC 350 also requires
testing of goodwill impairment to be at a reporting unit level and defines the
reporting unit as an operating segment, as that term is used in ASC Topic No.
280 “Segment
Reporting”, or one level below the operating segment (referred to as a
“component”), depending on whether certain criteria are met. At the
time of our annual assessment of goodwill, we had six reporting units with
goodwill and our impairment analysis was conducted at this level.
Goodwill impairment
is determined using a two-step process that requires management to make
judgments in determining what assumptions to use in the
calculation. The first step is to identify if a potential impairment
exists by comparing the fair value of the reporting unit with its carrying
amount, including goodwill. If the fair value of a reporting unit
exceeds its carrying amount, goodwill of the reporting unit is not considered to
have a potential impairment and the
second step of the
impairment test is not necessary. However, if the carrying amount of
a reporting unit exceeds its fair value, the second step is performed to
determine if goodwill is impaired and to measure the amount of impairment loss
to recognize, if any.
The second step
compares the implied fair value of goodwill with the carrying amount of
goodwill. If the implied fair value of goodwill exceeds the carrying
amount, then goodwill is not considered impaired. However, if the
carrying amount of goodwill exceeds the implied fair value, an impairment loss
is recognized in an amount equal to that excess. The implied
fair value of goodwill is determined in the same manner as the amount of
goodwill recognized in a business combination (i.e., the fair value of the
reporting unit is allocated to all the assets and liabilities, including any
unrecognized intangible assets, as if the reporting unit had been acquired in a
business combination).
We
use both the income approach and market approach to estimate the fair value of
our reporting units under the first step. Under the income approach, a
discounted cash flow analysis is performed requiring us to make various
judgmental assumptions about future revenue, operating margins, growth rates and
discount rates. These judgmental assumptions are based on our
budgets, long-term business plans, reserve reports, economic projections,
anticipated future cash flows and market place data. Under the market
approach, the fair value of each reporting unit is calculated by applying an
average peer total invested capital EBITDA (defined as earnings before interest,
income taxes and depreciation and amortization) multiple to the 2009 budgeted
EBITDA for each reporting unit. Judgment is required when selecting
peer companies that operate in the same or similar lines of business and are
potentially subject to the same corresponding economic risks.
Based on the first
step of the 2008 goodwill impairment analysis, the carrying amount of two of our
reporting units exceeded its fair value as calculated under the first step,
which required us to perform the second step of the impairment
test. In the second step, the fair value of tangible and certain
intangible assets was generally estimated using discounted cash flow
analysis. The fair value of intangibles with indefinite lives, such
as trademarks, was calculated using a royalty rate method. Based on
our 2008 goodwill and indefinite-lived intangible impairment analysis, in the
fourth quarter of 2008 we recorded a $704.3 million charge to write off the
remaining goodwill of our Oil and Gas segment. The impairment charges
associated with our oil and gas segment are recorded as a component of operating
loss in the accompanying consolidated statements of
operations. We also recorded a $10.7 million charge in
the fourth quarter of 2008 to write off the remaining goodwill and
indefinite-lived intangible assets associated with our acquisition of Helix
Energy Limited in 2005. Those impairment charges are reflected as
components of income (loss) from discontinued operations in the accompanying
consolidated statements of operations as a result of our sale
of Helix Energy Limited in April 2009. These impairment charges did
not have any current effect and will not have any future effect on cash flow or
our results of operations.
While we believe we
have made reasonable estimates and assumptions to calculate the fair value of
the reporting units and other intangible assets, it is possible a material
change could occur. We have $78.6 million of goodwill remaining
66
at
December 31, 2009. If our actual results are not consistent with our estimates
and assumptions used to calculate fair value, our results of operations may be
materially impacted as further impairments may occur.
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, 2009, our principal
non-U.S. subsidiaries had accumulated earnings and profits of approximately
$58.0 million. We have not provided deferred U.S. income tax on the
accumulated earnings and profits. The deconsolidation of CDI’s net income for
tax return filing purposes after its initial public offering did not have a
material impact on our consolidated results of operations; however, because of
our inability to recover our tax basis in CDI tax free, a long term deferred tax
liability is provided for any incremental increases to the book over tax
basis.
It
is our policy to provide for uncertain tax positions and the related interest
and penalties based upon management’s assessment of whether a tax benefit is
more likely than not to be sustained upon examination by tax authorities. At
December 31, 2009, we believe we have appropriately accounted for any
unrecognized tax benefits. To the extent we prevail in matters for which a
liability for an unrecognized tax benefit is established or are required to pay
amounts in excess of the liability, our effective tax rate in a given financial
statement period may be affected.
See Note 11 for
discussion of net operating loss carry forwards, deferred income taxes and
uncertain tax positions taken by the Company.
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 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.
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. Leasehold costs for producing properties are depleted using the
units-of-production method based on the amount of total estimated proved
reserves on a field-by-field basis. 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 asset’s carrying amount may not be recoverable. If an impairment is
indicated, the cash flows are discounted at a rate approximate to our cost of
capital and compared to the carrying value for determining the amount of the
impairment loss to record. Estimated future cash flows are based on management’s
expectations for the future and include estimates of crude oil and natural gas
reserves and future commodity prices, operating costs and future capital
expenditures. Downward revisions in estimates of proved reserve quantities or
expectations of falling commodity prices or rising operating costs could result
in a reduction in undiscounted future cash flows and could indicate a property
impairment. We recorded property impairments totaling $120.6 million in 2009
($55.9 million in the fourth quarter of 2009), $215.7 million in 2008 ($192.6
million in the fourth quarter of 2008) and approximately $64.1 million of
property impairments in 2007, primarily related to downward reserve revisions,
increased estimates of decommissioning costs and weak end of life well
performance in some of our domestic 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.
Management’s assessment of the results of exploration activities,
67
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. We recorded a total of $20.1 million in 2009 and $8.9 million in
2008 of exploration expense to write off certain unproved oil and gas properties
reflecting management’s assessment that exploration activities would not
commence prior to the respective lease expiration dates. During 2007, we
recorded $9.9 million of exploration expense to impair certain unproved
leasehold costs.
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. At December 31, 2007, we had two wells that were deemed to
be suspended wells under the criteria established by ASC Topic No. 932 “Extractive
Activities – Oil and Gas” (ASC 932.35.18-20). Following the
significant decrease in commodity prices in the second half of 2008 coupled with
the December 2008 announcement of our intention to sell all or a part of our oil
and gas business, we determined that further development of these wells was not
probable. Accordingly, we recorded a total of $18.8 million to
exploration expense to fully write off the capital costs associated with these
two suspended wells. We recorded an additional $0.5 million to write
off costs associated with suspended wells in 2009.
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.
During the years ended December 31, 2009, 2008 and 2007, we incurred $21.4
million, $27.7 million and $20.2 million, respectively, of exploratory
expenses, including the impairment of certain unproved leasehold costs as
discussed above in “Accounting
for Oil and Gas Properties” and in Note 6.
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,
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 engineer’s audit, and 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 estimated
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 estimated 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
68
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.
ACS Topic No. 410 “Asset
Retirement and Environmental Obligations” 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 historically
purchased producing offshore oil and gas properties that were in the later
stages of production. In conjunction with acquiring these properties, we assumed
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) 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 factors such 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 $248.1 million and
$225.8 million at December 31, 2009 and 2008,
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 risk management
activities involve the use of derivative financial instruments to hedge the
impact of market price risk exposure 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
contracts, primarily collars and swaps, for a portion of our oil and gas
production, interest rate swaps, and foreign currency forward contracts. Our oil
and gas costless collars and swaps, interest rate swaps, and foreign currency
forward exchange contracts are reflected in our balance sheet at fair value.
Hedge accounting does not apply to our oil and gas forward sales contracts as
these qualify for the normal purchase and sale scope exception under ASC Topic
No. 815 “Derivatives
and Hedging.”
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 (a component of shareholders’ equity) until the hedged transactions occur
and are recognized in earnings. The ineffective portion of a cash flow hedge’s
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 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
69
valuation
techniques or models to estimate market values. The fair value of our interest
rate swaps is calculated as the discounted cash flows of the difference between
the rate fixed by the hedge instrument and the LIBOR forward curve over the
remaining term of the hedge instrument. The fair value of our foreign currency
forward exchange contracts is calculated as the discounted cash flows of the
difference between the fixed payment as specified by the hedge instrument and
the expected cash inflow of the forecasted transaction using a foreign currency
forward curve.
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 expense is derived primarily
using the straight-line method over the estimated useful lives of the assets
(Note 2).
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 management’s
estimate of discounted cash flows.
Assets are
classified as held for sale when a formal plan to dispose of the assets exists
and those assets meet the held for sale criteria. Assets held for sale are
reviewed for potential loss on sale when the we commit 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 asset’s 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. We had no
assets that met the criteria of being classified as assets held for sale at
December 31, 2009.
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
vessel’s economic useful life or functional operating capability, are
capitalized and depreciated over the vessel’s 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, 2009 and 2008, capitalized deferred drydock charges (Note
7) totaled $12.0 million and $38.6 million, respectively. During the
years ended December 31, 2009, 2008 and 2007, drydock amortization expense
was $16.4 million, $26.0 million and $23.0 million, respectively.
We expect drydock amortization expense will decrease over the near term due to
our deconsolidation of CDI which will be partially offset with our commissioning
the vessels we have been constructing over the last three years.
Equity
Investments
We
periodically review our investments in Deepwater Gateway
and Independence Hub 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
70
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. During 2007, CDI
determined that there was an other than temporary impairment in OTSL and the
full value of CDI’s investment in OTSL was impaired and CDI recognized equity
losses of OTSL, inclusive of the impairment charge, of $10.8 million in
2007 (Note 8).
Worker’s
Compensation Claims
Our onshore
employees are covered by Worker’s 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 worker’s
compensation claims in the normal course of business, which management believes
are substantially covered by insurance. Our insurers and legal counsel analyze
each claim for potential exposure and estimate the ultimate liability of each
claim. Actual liability can be materially different from our estimates and can
have a direct impact on our liquidity and results of operations.
Recently
Issued Accounting Principles
In
June 2009, the Financial Accounting Standards Board (FASB) issued a new
accounting standard which
changes the consolidation rules as they relate to variable interest entities.
Specifically, the new standard makes significant changes to the model for
determining who should consolidate a variable interest entity, and also
addresses how often this assessment should be performed. We adopted this
standard in the first quarter of 2010 and the adoption did not have a material
impact on our consolidated financial statements.
In
August 2009, the FASB issued a new accounting standard which provides additional
guidance on the measurement of liabilities at fair value. Specifically,
when a quoted price in an active market for the identical liability is not
available, the new standard requires that the fair value of a liability be
measured using one or more of the valuation techniques that should maximize the
use of relevant observable inputs and minimize the use of unobservable
inputs. In addition, an entity is not required to include a separate input
or adjustment to other inputs relating to the existence of a restriction that
prevents the transfer of a liability. We adopted this standard in the
fourth quarter of 2009 and the adoption did not have a material impact on our
consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk.
We
are currently exposed to market risk in three major areas: interest rates,
commodity prices and foreign currency exchange rates.
Interest
Rate Risk. As of December 31, 2009, approximately 30% of
our outstanding debt was based on floating rates. Changes based on the floating
interest rates under our variable rate debt could result in an increase or
decrease in our annual interest expense and related cash outlay. To
reduce the impact of this market risk, in January 2010 we entered into various
cash flow hedging interest rate swaps to stabilize cash flows relating to
interest payments on $200 million of our Term Loan. The interest
rate applicable to our variable rate debt may rise, increasing our interest
expense. The impact of market risk is estimated using a hypothetical increase in
interest rates by 100 basis points for our variable rate long-term debt
that is not hedged. Based on this hypothetical assumption, we would have
incurred an additional $3.9 million in interest expense for the year ended
December 31, 2009.
Commodity
Price Risk. We have utilized derivative financial instruments
with respect to a portion of our 2010, 2009 and 2008 oil and gas production to
achieve a more predictable cash flow. We do not enter into derivative or other
financial instruments for trading purposes.
As
of December 31, 2009, we have the following volumes under derivatives
contracts related to our oil and gas producing activities totaling approximately
2.5 million barrels of oil and 25 Bcf of natural gas:
|
Production
Period
|
Instrument
Type
|
Average
Monthly
Volumes
|
Weighted
Average
Price
|
|||
|
Crude
Oil:
|
(per
barrel)
|
|||||
|
January 2010 — December
2010
|
Collar
|
|
100
MBbl
|
$62.50-$80.73
|
||
|
January 2010 — December
2010
|
Swap
|
77.1 MBbl
|
$76.99
|
|||
|
January 2010 — June 2010
|
Swap
|
50
MBbl
|
$71.08
|
|||
|
July
2010 — December
2010
|
Swap
|
15
MBbl
|
$74.07
|
|||
|
Natural
Gas:
|
(per
Mcf)
|
|||||
|
January 2010 — December
2010
|
Swap
|
1,079.2
Mmcf
|
$5.82
|
|||
|
January 2010 — December
2010
|
Collar
|
1,003.8
Mmcf
|
$6.00 — $6.70
|
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 with the
change in NYMEX prices.
Foreign
Currency Exchange Risk. Because we operate in various regions
in the world, we conduct a portion of our business in currencies other than the
U.S. dollar (primarily with respect to WOUK and WOSEA). The functional
currency for WOUK is the applicable local currency (British Pound). The
functional currency for WOSEA is the applicable local currency (Australian
Dollar). Although revenues are denominated in the local currency, the effects of
foreign currency fluctuations are partly mitigated because local expenses of
such foreign operations also generally are denominated in the same
currency.
Assets and
liabilities of WOUK and WOSEA are translated using the exchange rates in effect
at the balance sheet date, resulting in translation adjustments that are
reflected in accumulated other comprehensive income in the shareholders’ equity
section of our balance sheet. Approximately 9% of our assets are impacted by
changes in foreign currencies in relation to the U.S. dollar at
December 31, 2009. We recorded unrealized gains (losses) of $30.6 million,
$(71.1) million and $3.7 million to accumulated other comprehensive
income (loss) for the years ended December 31, 2009, 2008 and 2007,
respectively. Deferred taxes have not been provided on foreign currency
translation adjustments since we consider our undistributed earnings (when
applicable) of our non-U.S. subsidiaries to be permanently
reinvested.
We
also have subsidiaries with operations in the United Kingdom, Asia Pacific,
Europe and Australia. These international subsidiaries conduct the majority of
their operations in these regions in U.S. dollars which they consider the
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 resulted in a gain of
$2.2 million for the year ended December 31, 2009 and a $10.0
million loss for the year ended December 31, 2008. The amounts
for the year ended December 31, 2007 was not material to our results of
operations or cash flows.
Our
cash flows are subject to fluctuations resulting from changes in foreign
currency exchange rates. Fluctuations in exchange rates are
likely to impact our business and cash flow in the future. As a
result, we entered into various foreign currency forward purchase contracts to
stabilize expected cash outflows relating to certain vessel charters denominated
in British pounds. The aggregate fair value of the foreign currency forwards as
of December 31, 2009 and 2008 was a net asset (liability) of $2.1
million and $(0.9) million, respectively. In 2009, we recorded a $3.3 million
gain compared to a $1.1 million loss in 2008 as a result of the change in fair
value of our foreign currency forwards that did not qualify for hedge accounting
(Note 22).
Item 8. Financial Statements and Supplementary
Data.
INDEX
TO FINANCIAL STATEMENTS
|
|
Page
|
|
Management’s Report on
Internal Control Over Financial Reporting
|
74 |
| Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting | 75 |
|
Report of Independent
Registered Public Accounting Firm
|
76 |
|
Consolidated Balance Sheets as
of December 31, 2009 and 2008
|
77 |
|
Consolidated
Statements of Operations for the Years Ended December 31, 2009, 2008
and 2007
|
78 |
|
Consolidated
Statements of Shareholders’ Equity for the Years Ended December 31,
2009, 2008 and 2007
|
79 |
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2009, 2008
and 2007
|
81 |
|
Notes to the Consolidated
Financial Statements
|
83 |
MANAGEMENT'S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as
amended. The Company’s internal control system was designed to provide
reasonable assurance to the Company’s management and Board of Directors
regarding the reliability of financial reporting and the preparation and fair
presentation of financial statements for external purposes in accordance with
U.S. generally accepted accounting principles.
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
making its assessment, management has utilized the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control-Integrated
Framework. Based on this assessment, management has concluded that, as of
December 31, 2009, the Company’s internal control over financial reporting
is effective to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with U.S. generally accepted accounting
principles.
Ernst &
Young LLP has issued an attestation report on the Company’s internal control
over financial reporting as of December 31, 2009, which is included
herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
The
Board of Directors and Shareholders of
Helix
Energy Solutions Group, Inc. and Subsidiaries
We
have audited Helix Energy Solutions Group, Inc. and subsidiaries’ internal
control over financial reporting as of December 31, 2009, based on criteria
established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the COSO criteria). Helix
Energy Solutions Group, Inc. and subsidiaries’ management is responsible for
maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting
included in the accompanying Management’s Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the
company’s internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, 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
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In
our opinion, Helix Energy Solutions Group, Inc. and subsidiaries maintained, in
all material respects, effective internal control over financial reporting as of
December 31, 2009, 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, 2009 and
2008, and the related consolidated statements of operations, shareholders’
equity, and cash flows for each of the three years in the period ended December
31, 2009 of Helix Energy Solutions Group, Inc. and subsidiaries and our report
dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ Ernst &
Young LLP
Houston,
Texas
February
26, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
To
the Board of Directors and Shareholders of
Helix Energy
Solutions Group, Inc. and Subsidiaries
We
have audited the accompanying consolidated balance sheets of Helix Energy
Solutions Group, Inc. and subsidiaries as of December 31, 2009 and 2008, and the
related consolidated statements of operations, shareholders' equity, and cash
flows for each of the three years in the period ended December 31, 2009.
These financial statements are the responsibility of the Company's
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, 2009 and 2008, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles.
As
discussed in Note 2 to the consolidated financial statements, in 2009 the
Company changed its method of accounting for non-controlling interests in the
consolidated financial statements as a result of the adoption of a new
accounting standard and changed its reserve estimates and required disclosures
as a result of adopting new oil and gas reserve estimation and disclosure
requirements.
We
also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), Helix Energy Solutions Group,
Inc. and subsidiaries’ internal control over financial reporting as of December
31, 2009, 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 26, 2010 expressed an unqualified opinion
thereon.
/s/ Ernst & Young
LLP
Houston,
Texas
February 26,
2010
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash
equivalents
|
$
|
270,673
|
$
|
223,613
|
||||
|
Accounts
receivable —
Trade,
net of allowance for uncollectible accounts
of
$5,172 and $5,905
|
145,519
|
427,856
|
||||||
|
Unbilled
revenue
|
17,854
|
42,889
|
||||||
|
Costs
in excess of billing
|
9,305
|
74,361
|
||||||
|
Other current
assets
|
121,331
|
172,089
|
||||||
|
Current assets of
discontinued operations
|
878
|
19,215
|
||||||
|
Total
current assets
|
565,560
|
960,023
|
||||||
|
Property and equipment
|
4,352,109
|
4,742,051
|
||||||
|
Less — Accumulated
depreciation
|
(1,488,403
|
)
|
(1,323,608
|
)
|
||||
|
2,863,706
|
3,418,443
|
|||||||
|
Other
assets:
|
||||||||
|
Equity
investments
|
189,411
|
196,660
|
||||||
|
Goodwill, net
|
78,643
|
366,218
|
||||||
|
Other assets,
net
|
82,213
|
125,722
|
||||||
|
$
|
3,779,533
|
$
|
5,067,066
|
|||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$
|
155,457
|
$
|
344,807
|
||||
|
Accrued
liabilities
|
200,156
|
231,679
|
||||||
|
Current maturities
of long-term debt
|
12,424
|
93,540
|
||||||
|
Current
liabilities from discontinued operations
|
451
|
2,772
|
||||||
|
Total
current liabilities
|
368,488
|
672,798
|
||||||
|
Long-term debt
|
1,348,315
|
1,933,686
|
||||||
|
Deferred income taxes
|
442,607
|
615,504
|
||||||
|
Decommissioning
liabilities
|
182,399
|
194,665
|
||||||
|
Other long-term
liabilities
|
4,262
|
81,637
|
||||||
|
Total
liabilities
|
2,346,071
|
3,498,290
|
||||||
|
Convertible preferred
stock
|
6,000
|
55,000
|
||||||
|
Commitments
and contingencies
|
||||||||
|
Shareholders’
equity:
|
||||||||
|
Common
stock, no par, 240,000 shares authorized,
104,281
and 91,972 shares issued
|
907,691
|
806,905
|
||||||
|
Retained
earnings
|
519,807
|
417,940
|
||||||
|
Accumulated other
comprehensive loss
|
(22,241
|
)
|
(33,696
|
)
|
||||
|
Total
controlling interest shareholders’ equity
|
1,405,257
|
1,191,149
|
||||||
|
Noncontrolling
interests
|
22,205
|
322,627
|
||||||
|
Total
equity
|
1,427,462
|
1,513,776
|
||||||
|
$
|
3,779,533
|
$
|
5,067,066
|
|||||
The accompanying
notes are an integral part of these consolidated financial
statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
Year Ended
December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
thousands, except per share amounts)
|
||||||||||||
|
Net revenues:
|
||||||||||||
|
Contracting
services
|
$
|
1,076,349
|
$
|
1,568,221
|
$
|
1,147,857
|
||||||
|
Oil and gas
|
385,338
|
545,853
|
584,563
|
|||||||||
|
1,461,687
|
2,114,074
|
1,732,420
|
||||||||||
|
Cost of
sales:
|
||||||||||||
|
Contracting
services
|
854,975
|
1,135,429
|
762,812
|
|||||||||
|
Oil and gas
|
218,617
|
357,853
|
372,904
|
|||||||||
|
Oil and gas
property impairments
|
120,550
|
215,675
|
64,072
|
|||||||||
|
Exploration
expense
|
24,383
|
32,926
|
26,725
|
|||||||||
|
1,218,525
|
1,741,883
|
1,226,513
|
||||||||||
|
Gross
profit
|
243,162
|
372,191
|
505,907
|
|||||||||
|
Goodwill and
other indefinite-lived intangible impairments
|
—
|
704,311
|
—
|
|||||||||
|
Gain on oil
and gas derivative commodity contracts
|
89,485
|
21,599
|
—
|
|||||||||
|
Gain on sale of assets,
net
|
2,019
|
73,471
|
50,368
|
|||||||||
|
Selling and administrative
expenses
|
130,851
|
177,172
|
144,996
|
|||||||||
|
Income (loss) from
operations
|
203,815
|
(414,222
|
)
|
411,279
|
||||||||
|
Equity in earnings
of investments
|
32,329
|
31,854
|
19,573
|
|||||||||
|
Gain on sale of
Cal Dive common stock
|
77,343
|
—
|
151,696
|
|||||||||
|
Net interest
expense and other
|
51,495
|
111,098
|
67,047
|
|||||||||
|
Income (loss) before income
taxes
|
261,992
|
(493,466
|
)
|
515,501
|
||||||||
|
Provision for
income taxes
|
(95,822
|
)
|
(86,779
|
)
|
(171,862
|
)
|
||||||
|
Income (loss) from continuing
operations
|
166,170
|
(580,245
|
)
|
343,639
|
||||||||
|
Income (loss)
from discontinued operations, net of tax
|
9,581
|
(9,812
|
)
|
1,347
|
||||||||
|
Net income
(loss), including noncontrolling interests
|
175,751
|
(590,057
|
)
|
344,986
|
||||||||
|
Net income
applicable to noncontrolling interests
|
(19,697
|
)
|
(45,873
|
)
|
(29,288
|
)
|
||||||
|
Net income (loss) applicable
to Helix
|
156,054
|
(635,930
|
)
|
315,698
|
||||||||
|
Preferred stock
dividends
|
(748
|
)
|
(3,192
|
)
|
(3,716
|
)
|
||||||
|
Preferred
stock beneficial conversion charges
|
(53,439
|
)
|
—
|
—
|
||||||||
|
Net income
(loss) applicable to Helix common shareholders
|
$
|
101,867
|
$
|
(639,122
|
)
|
$
|
311,982
|
|||||
|
Basic
earnings (loss) per share of common stock:
|
||||||||||||
|
Continuing
operations
|
$
|
0.92
|
$
|
(6.94
|
)
|
$
|
3.40
|
|||||
|
Discontinued
operations
|
0.09
|
(0.11
|
)
|
0.02
|
||||||||
|
Net
income (loss) per common
share
|
$
|
1.01
|
$
|
(7.05
|
)
|
$
|
3.42
|
|||||
|
Diluted
earnings (loss) per share of common stock:
|
||||||||||||
|
Continuing
operations
|
$
|
0.87
|
$
|
(6.94
|
)
|
$
|
3.25
|
|||||
|
Discontinued
operations
|
0.09
|
(0.11
|
)
|
0.01
|
||||||||
|
Net
income (loss) per common
share
|
$
|
0.96
|
$
|
(7.05
|
)
|
$
|
3.26
|
|||||
|
Weighted
average common shares outstanding:
|
||||||||||||
|
Basic
|
99,136
|
90,650
|
90,086
|
|||||||||
|
Diluted
|
105,720
|
90,650
|
95,647
|
|||||||||
The accompanying
notes are an integral part of these consolidated financial
statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’ EQUITY
(amounts
in thousands)
|
Helix
Energy Solutions Shareholders’ Equity
|
|||||||||||||||||||||||||||
|
Common
Stock
|
|||||||||||||||||||||||||||
|
Shares
|
Amount
|
Retained
Earnings
|
Accumulated
Other
Comprehensive Income (Loss)
|
Total
controlling interest shareholders’ equity
|
Non-controlling
Interest
|
Total
Equity
|
|||||||||||||||||||||
|
Balance, December 31, 2006
|
90,628
|
783,998
|
$
|
745,080
|
$
|
27,236
|
$
|
1,556,314
|
$
|
59,802
|
$
|
1,616,116
|
|||||||||||||||
|
Comprehensive
income:
|
|||||||||||||||||||||||||||
|
Net
income
|
—
|
—
|
315,698
|
—
|
315,698
|
29,288
|
344,986
|
||||||||||||||||||||
|
Foreign
currency translations
adjustments
|
—
|
—
|
—
|
3,680
|
3,680
|
—
|
3,680
|
||||||||||||||||||||
|
Unrealized
loss on hedges, net
|
—
|
—
|
—
|
(9,654
|
)
|
(9,654
|
)
|
—
|
(9,654
|
)
|
|||||||||||||||||
|
Comprehensive income
|
309,724
|
29,288
|
339,012
|
||||||||||||||||||||||||
|
Reclass
unamortized discount on convertible senior notes to reflect temporary
equity status (Note 2)
|
—
|
(42,201
|
)
|
—
|
—
|
(42,201
|
)
|
—
|
(42,201
|
)
|
|||||||||||||||||
|
Convertible
preferred stock dividends
|
—
|
—
|
(3,716
|
)
|
—
|
(3,716
|
)
|
—
|
(3,716
|
)
|
|||||||||||||||||
|
Stock
compensation expense
|
—
|
14,607
|
—
|
—
|
14,607
|
—
|
14,607
|
||||||||||||||||||||
|
Stock repurchase
|
(282
|
)
|
(9,904
|
)
|
—
|
—
|
(9,904
|
)
|
—
|
(9,904
|
)
|
||||||||||||||||
|
Activity in
company stock plans, net
|
1,039
|
4,547
|
—
|
—
|
4,547
|
—
|
4,547
|
||||||||||||||||||||
|
Excess tax
benefit from stock-
based
compensation
|
—
|
580
|
—
|
—
|
580
|
—
|
580
|
||||||||||||||||||||
|
Investments
in or dispositions of common stock of consolidated subsidiaries in which
Helix has a noncontrolling interest (Note
2)
|
—
|
—
|
—
|
—
|
—
|
174,836
|
174,836
|
||||||||||||||||||||
|
Balance,
December 31, 2007
|
91,385
|
751,627
|
1,057,062
|
21,262
|
1,829,951
|
263,926
|
2,093,877
|
||||||||||||||||||||
|
Comprehensive
income (loss)
|
|||||||||||||||||||||||||||
|
Net income
(loss )
|
—
|
—
|
(635,930
|
)
|
—
|
(635,930
|
)
|
45,873
|
(590,057
|
)
|
|||||||||||||||||
|
Foreign
currency translations
adjustments
|
—
|
—
|
—
|
(71,134
|
)
|
(71,134
|
)
|
(93
|
)
|
(71,227
|
)
|
||||||||||||||||
|
Unrealized
loss (gain) on hedges, net
|
—
|
—
|
—
|
16,176
|
16,176
|
(480
|
)
|
15,696
|
|||||||||||||||||||
|
Comprehensive loss
|
(690,888
|
)
|
45,300
|
(645,588
|
)
|
||||||||||||||||||||||
|
Reclass
unamortized discount on convertible senior notes to shareholders’ equity
(Note 2)
|
—
|
42,201
|
—
|
—
|
42,201
|
—
|
42,201
|
||||||||||||||||||||
|
Convertible
preferred stock dividends
|
—
|
—
|
(3,192
|
)
|
—
|
(3,192
|
)
|
—
|
(3,192
|
)
|
|||||||||||||||||
|
Other
|
—
|
(3,952
|
)
|
—
|
—
|
(3,952
|
)
|
—
|
(3,952
|
)
|
|||||||||||||||||
|
Stock
compensation expense
|
—
|
15,506
|
—
|
—
|
15,506
|
—
|
15,506
|
||||||||||||||||||||
|
Stock repurchase
|
(110
|
)
|
(3,925
|
)
|
—
|
—
|
(3,925
|
)
|
—
|
(3,925
|
)
|
||||||||||||||||
|
Activity in
company stock plans, net
|
697
|
4,113
|
—
|
—
|
4,113
|
—
|
4,113
|
||||||||||||||||||||
|
Excess tax
benefit from stock-
based
compensation
|
—
|
1,335
|
—
|
—
|
1,335
|
—
|
1,335
|
||||||||||||||||||||
|
Investments
in or dispositions of common stock of consolidated subsidiaries in which
Helix has a noncontrolling interest (Note
2)
|
—
|
—
|
—
|
—
|
—
|
13,401
|
13,401
|
||||||||||||||||||||
|
Balance,
December 31, 2008
|
91,972
|
$
|
806,905
|
$
|
417,940
|
$
|
(33,696
|
)
|
$
|
1,191,149
|
$
|
322,627
|
$
|
1,513,776
|
|||||||||||||
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’ EQUITY
(Continued)
(amounts
in thousands)
|
Helix
Energy Solutions Shareholders’ Equity
|
|||||||||||||||||||||||||
|
Common
Stock
|
|||||||||||||||||||||||||
|
Shares
|
Amount
|
Retained
Earnings
|
Accumulated
Other
Comprehensive Income (Loss)
|
Total
controlling interest shareholders’ equity
|
Non-controlling
Interest
|
Total
Equity
|
|||||||||||||||||||
|
Balance,
December 31, 2008
|
91,972
|
$
|
806,905
|
$
|
417,940
|
$
|
(33,696
|
)
|
$
|
1,191,149
|
$
|
322,627
|
$
|
1,513,776
|
|||||||||||
|
Comprehensive
income (loss)
|
|||||||||||||||||||||||||
|
Net
income
|
—
|
—
|
156,054
|
—
|
156,054
|
19,697
|
175,751
|
||||||||||||||||||
|
Effect
of deconsolidation of Cal Dive (Note
3)
|
—
|
—
|
—
|
—
|
—
|
(320,119
|
)
|
(320,119
|
)
|
||||||||||||||||
|
Foreign
currency translations
adjustments
|
—
|
—
|
—
|
30,617
|
30,617
|
—
|
30,617
|
||||||||||||||||||
|
Unrealized
loss (gain) on hedges, net
|
—
|
—
|
—
|
(18,275
|
)
|
(18,275
|
)
|
—
|
(18,275
|
)
|
|||||||||||||||
|
Unrealized
loss on investment held for sale
|
—
|
—
|
—
|
(887
|
)
|
(887
|
)
|
—
|
(887
|
)
|
|||||||||||||||
|
Comprehensive loss
|
167,509
|
(300,422
|
)
|
(132,913
|
)
|
||||||||||||||||||||
|
Convertible
preferred stock dividends and preferred stock beneficial
charges
|
—
|
—
|
(54,187
|
)
|
—
|
(54,187
|
)
|
—
|
(54,187
|
)
|
|||||||||||||||
|
Convertible
preferred stock redemptions
|
12,805
|
102,502
|
—
|
—
|
102,502
|
—
|
102,502
|
||||||||||||||||||
|
Other
|
—
|
(319
|
)
|
—
|
—
|
(319
|
)
|
—
|
(319
|
)
|
|||||||||||||||
|
Stock
compensation expense
|
—
|
9,530
|
—
|
—
|
9,530
|
—
|
9,530
|
||||||||||||||||||
|
Stock repurchase
|
(1,116
|
)
|
(13,995
|
)
|
—
|
—
|
(13,995
|
)
|
—
|
(13,995
|
)
|
||||||||||||||
|
Activity in
company stock plans, net
|
620
|
2,173
|
—
|
—
|
2,173
|
—
|
2,173
|
||||||||||||||||||
|
Excess tax
benefit from stock-
based
compensation
|
—
|
895
|
—
|
—
|
895
|
—
|
895
|
||||||||||||||||||
|
Balance,
December 31, 2009
|
104,281
|
$
|
907,691
|
$
|
519,807
|
$
|
(22,241
|
)
|
$
|
1,405,257
|
$
|
22,205
|
$
|
1,427,462
|
|||||||||||
The accompanying
notes are an integral part of these consolidated financial
statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
thousands)
|
||||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Net
income (loss), including noncontrolling interests
|
$
|
175,751
|
$
|
(590,057
|
)
|
$
|
344,986
|
|||||
|
Adjustments
to reconcile net income (loss), including noncontrolling interests to net
cash provided by
operating
activities —
|
||||||||||||
|
Depreciation
and
amortization
|
262,617
|
333,726
|
329,798
|
|||||||||
|
Asset
impairment
charges
|
121,855
|
215,675
|
64,072
|
|||||||||
|
Goodwill
and other indefinite-lived intangible impairments
|
—
|
704,311
|
—
|
|||||||||
|
Exploratory
drilling and related expenditures
|
21,367
|
27,703
|
20,187
|
|||||||||
|
Equity
in (earnings) loss of investments, net
of distributions
|
(6,321
|
)
|
2,846
|
697
|
||||||||
|
Equity
in losses of OTSL, inclusive of impairment charge
|
—
|
—
|
10,841
|
|||||||||
|
Amortization
of deferred financing
costs
|
6,693
|
5,641
|
6,939
|
|||||||||
|
(Income)
loss from discontinued operations
|
(9,581
|
)
|
9,658
|
(1,345
|
)
|
|||||||
|
Stock
compensation
expense
|
11,992
|
21,412
|
17,302
|
|||||||||
|
Amortization
of debt
discount
|
7,880
|
7,385
|
6,920
|
|||||||||
|
Deferred
income
taxes
|
(64,926
|
)
|
(5,402
|
)
|
125,083
|
|||||||
|
Excess
tax benefit from stock-based compensation
|
(895
|
)
|
(1,335
|
)
|
(580
|
)
|
||||||
|
Unrealized
gain on derivative
contracts
|
(5,237
|
)
|
(1,669
|
)
|
—
|
|||||||
|
Gain
on investment in Cal Dive common stock
|
(77,343
|
)
|
—
|
(151,696
|
)
|
|||||||
|
Gain
on sale of
assets
|
(2,019
|
)
|
(73,471
|
)
|
(50,368
|
)
|
||||||
|
Changes
in operating assets and liabilities:
|
||||||||||||
|
Accounts
receivable,
net
|
52,245
|
(36,956
|
)
|
(6,758
|
)
|
|||||||
|
Other
current
assets
|
49,028
|
(4,958
|
)
|
(22,351
|
)
|
|||||||
|
Income
tax
payable
|
48,831
|
(12,937
|
)
|
(153,804
|
)
|
|||||||
|
Accounts
payable and accrued liabilities
|
(62,341
|
)
|
(126,082
|
)
|
(52,362
|
)
|
||||||
|
Oil
and gas decommissioning expenditures
|
(45,038
|
)
|
(25,809
|
)
|
(12,813
|
)
|
||||||
|
Other
noncurrent,
net
|
(62,750
|
)
|
(15,267
|
)
|
(53,973
|
)
|
||||||
|
Cash
provided by operating
activities
|
421,808
|
434,414
|
420,775
|
|||||||||
|
Cash
provided by (used in) discontinued operations
|
(6,261
|
)
|
3,305
|
(4,449
|
)
|
|||||||
|
Net
cash provided by operating activities
|
415,547
|
437,719
|
416,326
|
|||||||||
|
Cash flows
from investing activities:
|
||||||||||||
|
Capital
expenditures
|
(423,373
|
)
|
(855,054
|
)
|
(942,381
|
)
|
||||||
|
Acquisition
of businesses, net of cash acquired
|
—
|
—
|
(147,498
|
)
|
||||||||
|
(Purchases)
sale of short-term investments
|
—
|
—
|
285,395
|
|||||||||
|
Investments
in equity
investments
|
(1,657
|
)
|
(846
|
)
|
(17,459
|
)
|
||||||
|
Distributions
from equity investments,
net
|
6,742
|
11,586
|
6,679
|
|||||||||
|
Proceeds
from insurance
reimbursement
|
—
|
13,200
|
—
|
|||||||||
|
Proceeds
from sale of Cal Dive common stock
|
418,168
|
—
|
—
|
|||||||||
|
Reduction
in cash from deconsolidation of Cal Dive
|
(112,995
|
)
|
—
|
—
|
||||||||
|
Proceeds
from sales of
property
|
23,717
|
274,230
|
78,073
|
|||||||||
|
Other,
net
|
(6
|
)
|
(614
|
)
|
(1,248
|
)
|
||||||
|
Cash
used in investing
activities
|
(89,404
|
)
|
(557,498
|
)
|
(738,439
|
)
|
||||||
|
Cash provided by (used
in) discontinued operations
|
20,872
|
(476
|
)
|
(1,215
|
)
|
|||||||
|
Net
cash used in investing
activities
|
$ |
(68,532
|
)
|
$ |
(557,974
|
)
|
$ |
(739,654
|
)
|
|||
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Continued)
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash flows
from financing activities:
|
||||||||||||
|
Repayment
of Helix term
loan
|
(4,326
|
)
|
(4,326
|
)
|
(405,408
|
)
|
||||||
|
Borrowings
on Helix
Revolver
|
—
|
1,021,500
|
472,800
|
|||||||||
|
Repayments
on Helix
Revolver
|
(349,500
|
)
|
(690,000
|
)
|
(454,800
|
)
|
||||||
|
Borrowings
on unsecured senior
debt
|
—
|
—
|
550,000
|
|||||||||
|
Repayment
of MARAD
borrowings
|
(4,214
|
)
|
(4,014
|
)
|
(3,823
|
)
|
||||||
|
Borrowings
on CDI
Revolver
|
100,000
|
61,100
|
31,500
|
|||||||||
|
Repayments
on CDI
Revolver
|
—
|
(61,100
|
)
|
(332,668
|
)
|
|||||||
|
Borrowings
on CDI term
loan
|
—
|
—
|
375,000
|
|||||||||
|
Repayments
on CDI term
loan
|
(20,000
|
)
|
(60,000
|
)
|
—
|
|||||||
|
Borrowing
under loan
notes
|
—
|
—
|
5,000
|
|||||||||
|
Deferred
financing
costs
|
(6,970
|
)
|
(1,796
|
)
|
(17,165
|
)
|
||||||
|
Capital
lease
payments
|
—
|
(1,505
|
)
|
(2,519
|
)
|
|||||||
|
Preferred
stock dividends
paid
|
(645
|
)
|
(3,192
|
)
|
(3,716
|
)
|
||||||
|
Repurchase
of common
stock
|
(13,995
|
)
|
(3,925
|
)
|
(9,904
|
)
|
||||||
|
Excess
tax benefit from stock-based compensation
|
895
|
1,335
|
580
|
|||||||||
|
Exercise
of stock options,
net
|
176
|
2,139
|
1,568
|
|||||||||
|
Net
cash (used in) provided by financing activities
|
(298,579
|
)
|
256,216
|
206,445
|
||||||||
|
Effect of
exchange rate changes on cash and cash equivalents
|
(1,376
|
)
|
(1,903
|
)
|
174
|
|||||||
|
Net increase
(decrease) in cash and cash equivalents
|
47,060
|
134,058
|
(116,709
|
)
|
||||||||
|
Cash and cash
equivalents:
|
||||||||||||
|
Balance,
beginning of
year
|
223,613
|
89,555
|
206,264
|
|||||||||
|
Balance,
end of
year
|
$
|
270,673
|
$
|
223,613
|
$
|
89,555
|
||||||
The accompanying
notes are an integral part of these consolidated financial
statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization
Effective
March 6, 2006, we changed our name from Cal Dive International, Inc.
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. Until June 2009, Cal Dive
International, Inc. (collectively with its subsidiaries referred to as
“Cal Dive” or “CDI”) was a majority-owned subsidiary of
Helix. Helix sold substantially all its remaining ownership interests
in Cal Dive during 2009 (Note 3). We are an international offshore energy
company that provides development solutions and other contracting services to
the energy market as well as to our own oil and gas properties. Our Contracting
Services segment utilizes our vessels, offshore equipment and proprietary
technologies to deliver services that may reduce finding and development costs
and cover the complete lifecycle of an offshore oil and gas field. Our
Contracting Services are located primarily in Gulf of Mexico, North Sea, Asia
Pacific, and West Africa regions. Our Oil and Gas segment engages in prospect
generation, exploration, development and production activities. Our oil and gas
operations are almost exclusively located in the Gulf of Mexico.
Contracting
Services Operations
We
seek to provide services and methodologies which we believe are critical to
finding and developing offshore reservoirs and maximizing production
economics. Our “life of field” services are segregated into three
disciplines: subsea construction, well operations and production facilities. We
have disaggregated our contracting services operations into three reportable
segments: Contracting Services; Shelf Contracting; and Production Facilities.
Our Contracting Services business includes deepwater construction, well
operations and drilling. Our former Shelf Contracting business
represents the assets of CDI, of which we owned 57.2% at December 31, 2008. In
2009, we sold substantially all our remaining ownership of CDI through various
transactions (Note 3). Our Production Facilities business includes
our investments in Deepwater Gateway, L.L.C. (“Deepwater
Gateway”), Independence Hub, LLC (“Independence Hub”) and Kommandor
LLC (“Kommandor”).
Oil
and Gas Operations
We
began our oil and gas operations to provide a more efficient solution to
offshore abandonment, to expand our off-season asset utilization of our
contracting services business and to achieve incremental returns. We have
evolved this business model to include not only mature oil and gas properties
but also proved and unproved reserves yet to be developed and explored. 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.
Discontinued
Operations
In April 2009, we sold Helix Energy
Limited (“HEL”), our former reservoir technology consulting business, to a
subsidiary of Baker Hughes Incorporated for $25 million. As a result
of the sale of HEL, which entity’s operations were conducted by its wholly owned
subsidiary, Helix RDS Limited (“Helix RDS”), we have presented the results of
Helix RDS as discontinued operations in the accompanying consolidated financial
statements. HEL and Helix RDS were previously components of our
Contracting Services segment. We recognized an $8.3 million
gain on the sale of HEL.
Economic
Outlook
The economic
downturn and weakness in the equity and credit capital markets continue to
contribute to the uncertainty regarding the outlook of the global
economy. This uncertainty, coupled with the negative near-term
outlook for global demand for oil and natural gas, resulted in commodity price
declines over the second half of 2008, with significant declines occurring in
the fourth quarter of 2008. Natural gas prices continued to decline
in 2009 with prices reaching near decade low levels. A decline in oil
and natural gas prices negatively impacts our operating results and cash
flows. Our stock price also significantly declined over the
second half of 2008. The declines in our stock price and the prices
of oil and natural gas were considered in association with our required annual
impairment assessment of goodwill and properties at year end 2008, which
resulted in significant impairment charges (Note 2). Our stock price
decreased further in the first
83
quarter of 2009
resulting in our assessment of our goodwill amounts as of March 31, 2009;
however, no further impairments were required. Our stock price
subsequently increased and no further impairment of goodwill was required in
2009. At December 31, 2009 our remaining goodwill totaled $78.6
million, all of which is attributable to our Contracting Services
segment.
Our Contracting
Services segment may be negatively impacted by low commodity prices as some of
our customers, primarily oil and gas companies, have announced their intention
to reduce capital spending. With respect to our oil and gas
operations, we hedged the price risk for a significant portion of our
anticipated oil and gas production for 2010 when we entered into commodity
hedges during 2009. These hedge contracts enable us to minimize our
near-term cash flow risks related to declining commodity prices. See
Note 22 for additional information regarding our oil and gas hedge
contracts.
Note 2 —
Summary of Significant Accounting Policies
Principles
of Consolidation
Our consolidated financial
statements include the accounts of majority-owned subsidiaries. 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 consolidated our former subsidiary CDI until June 10, 2009, at
which time our ownership in CDI was reduced to less than
50%. We recorded our proportional share of CDI’s results under
the equity method of accounting until we sold substantially all our remaining
ownership interests in CDI on September 23, 2009. We also
account for our Deepwater Gateway and Independence Hub investments under the
equity method of accounting. Minority interests represents the minority
shareholders’ proportionate share of the equity in CDI, until we deconsolidated
its results in June 2009, and Kommandor LLC. 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, including
the separate line disclosures of goodwill, oil and gas property impairment
charges and exploration expense in the consolidated statements of operations
reflecting the material amount of such charges, the adoption of certain recent
accounting pronouncements that require retrospective application and the
presentation of a former business unit as discontinued operations (Note
1). We have conducted our subsequent events review through February
26, 2010, the date our financial statements were filed with the Securities and
Exchange Commission (“SEC”).
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 both December 31, 2009 and 2008, we had $35.4 million of restricted cash
included in other assets (Note 7), all of which was related to funds required to
be escrowed to cover decommissioning liabilities associated with the acquisition
of the South Marsh Island Block 130 property in 2002. Under the purchase
agreement for that property, we are obligated to escrow 50% of revenues
on the first $20 million of production escrow and then 37.5% of
revenues on production until a total of $33 million is
escrowed. At December 31, 2009 the full escrow requirement under this
agreement was met and is available for the future decommissioning of
this field.
The following table
provides supplemental cash flow information for the periods stated (in
thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Interest
paid, net of interest
capitalized
|
$
|
48,313
|
$
|
53,000
|
$
|
71,706
|
||||||
|
Income taxes
paid
|
$
|
106,480
|
$
|
106,624
|
$
|
203,873
|
||||||
Non-cash investing
activities for the years ended December 31, 2009, 2008 and 2007 included
$48.9 million, $78.5 million and $90.7 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.
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. The amount of our net accounts receivable
approximate fair value. We establish an allowance for uncollectible
accounts receivable based on historical experience and any specific customer
collection issues that we have identified. Uncollectible 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 (Note 19).
Inventories
We
had inventory totaling $25.8 million at December 31, 2009 and $32.2 million at
December 31, 2008. Our inventory primarily represents the cost
of supplies to be used in our oil and gas drilling and development activities,
primarily drilling pipe, tubulars and certain wellhead equipment, including two
subsea trees. These costs will be partially reimbursed by third party
participants in wells supplied with these
materials. Our inventories are stated at the lower of cost
or market value. For the year ended December 31, 2009, we recorded an
aggregate of $1.8 million of charges to cost of sales to reduce our inventory to
its lower of cost or market value at various times throughout the year,
including $0.7 million at December 31, 2009. At December
31, 2008, we recorded $2.4 million of similar charges
to reduce our inventory to its then estimated market value as of that
date.
Property
and Equipment
Overview. Property
and equipment, both owned and under capital leases, are recorded at cost. The
following is a summary of the gross components of property and equipment
(dollars in thousands):
|
Estimated
Useful
Life
|
2009
|
2008
|
|||||||
|
Vessels
|
10 to 30
years
|
$
|
1,542,403
|
$
|
1,941,733
|
||||
|
Oil and gas
leases and related
equipment
|
Units-of-Production
|
2,665,720
|
2,564,851
|
||||||
|
Machinery,
equipment, buildings and leasehold improvement
|
5 to 30
years
|
143,986
|
235,467
|
||||||
|
Total
property and
equipment
|
$
|
4,352,109
|
$
|
4,742,051
|
The cost of repairs
and maintenance is charged to expense as incurred, while the cost of
improvements is capitalized. Total repair and maintenance expenses totaled
$35.6 million, $72.4 million and $44.1 million for the years
ended December 31, 2009, 2008 and 2007, respectively. Included
in machinery, equipment, buildings and leasehold improvements were $19.5 million
and $21.0 million of capitalized software costs at December 31, 2009 and 2008,
respectively. Total amount charged to expense related to the
amortization of these software costs was $2.6 million, $1.2 million and $0.3
million for the years ended December 31, 2009, 2008 and 2007,
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
85
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 flow 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, an estimate of discounted cash flows or a combination of the
two. During the fourth quarter of 2009, we recorded an aggregate $1.3
million charge to reduce the carrying value of certain specific ROV equipment to
its net realizable value. There were no such impairments related to
our vessels during 2009, 2008 and 2007. See Note 6 for disclosure related to our
oil and gas properties.
Assets are
classified as held for sale when we have a formalized plan for disposal of
certain assets and those assets meet the held for sale criteria. Assets
classified as held for sale are included in other current
assets. There were no assets meeting the requirements to be
classified as assets held for sale at December 31, 2009 and 2008. As
further discussed in Note 3, we own 500,000 shares of CDI common stock that we
classify as an investment held for sale. Accordingly, we mark these
shares to market at each period end based on the quoted stock price of CDI
common stock on the NYSE, and record the change in the fair value of shares as a
charge reflected within accumulated comprehensive income (loss) (Note
14).
Depreciation
and Depletion. Depletion expense is determined on a
field-by-field basis using the units-of-production method, with depletion rates
for leasehold acquisition costs based on estimated total remaining proved
reserves. Depletion rates for well and related facility costs are
based on estimated total remaining proved developed reserves associated with
each individual field. The depletion rates are changed whenever there
is an indication of the need for a revision but, at a minimum, are evaluated
annually. Any such revisions are accounted for prospectively as a
change in accounting estimate.
Oil
and Gas Properties. Almost all of our interests in oil and gas
properties are located offshore in the Gulf of Mexico and located in waters
regulated by the United States. We follow the successful efforts method of
accounting for our natural gas and oil exploration and development activities.
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 and
are reflected as a reduction of investing cash flow in the accompanying
consolidated statements of cash flow. Costs incurred relating to unsuccessful
exploratory wells are expensed in the period when the drilling is determined to
be unsuccessful and are included as a reconciling item to net income (loss) in
operating activities in the accompanying consolidated statements of cash flow.
See “— Exploratory Costs” below.
Proved
Properties. We assess proved oil and gas properties for
possible impairment at least annually or when events or circumstances indicate
that the recorded carrying value of the properties may not be recoverable. We
recognize an impairment loss as a result of a triggering event and when the
estimated undiscounted future cash flows from a property are less than the
carrying value. If an impairment is indicated, the cash flows are discounted at
a rate approximate to our cost of capital and compared to the carrying value for
determining the amount of the impairment loss to record. In the discounted
cash flow method, the estimated future cash flows are based on prices based on
published forward commodity price curves as of the date of the estimate and
management's estimates of future operating and development costs and a risk
adjusted discount rate. Downward revisions in estimates of reserve
quantities or expectations of falling commodity prices or rising operating costs
could result in a reduction in undiscounted future cash flows and could indicate
a property impairment. We recorded approximately $120.6 million, $215.7 million
and $64.1 million of property impairments in 2009, 2008 and 2007, respectively,
primarily related to downward reserve revisions, weak end of life well
performance in some of our domestic properties, fields lost as a result of
Hurricanes Gustav
and Ike,
and the reassessment of the economics of some of our marginal fields in light of
current oil and gas market conditions. These impairment charges included a total
of $55.9 million in the fourth quarter of 2009 and $192.6 million in the fourth
quarter of 2008.
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. Management’s 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. We recorded
impairments to unproved oil and gas properties totaling $20.1 million in 2009,
$8.9 million in 2008 and $9.9 million in 2007. Such impairments were
included in exploration expenses for our Oil and Gas
segment.
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 exploration expense, and we continue to capitalize the
costs associated with the salvageable portion of the well bore which increase
the capital cost basis of 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 reflect 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 all the capitalized
costs to dry hole exploration expense. During the year ended December 31,
2009, 2008 and 2007, we incurred $21.4 million, $27.7 million and
$20.2 million, respectively, of exploratory expense; including $0.6
million, $18.8 million and $10.3 million of dry hole expense. See
“— Note 6 — 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 to be appropriate
at the time of the acquisition. To compensate for inherent risks of estimating
and valuing unproved reserves, probable and possible reserves are reduced by
additional risk weighting factors. See Note 5 for a detailed discussion of our
acquisition of Remington.
Capitalized
Interest. Interest from external borrowings is capitalized on
major projects until the assets are ready for their intended use. Capitalized
interest is added to the cost of the underlying asset and is amortized over the
useful lives of the asset in the same manner as the underlying asset. The total
of our interest expense capitalized during each of the three years ended
December 31, 2009, 2008 and 2007 was $48.1 million, $42.1 million and $31.8
million, respectively.
Equity
Investments
We
periodically review our investments in Deepwater Gateway and Independence Hub
for impairment. Under the equity method of accounting, an impairment loss would
be recorded whenever the fair value of an equity investment is determined to be
below its carrying amount and the reduction is considered 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 long-term operating
and financial prospects of the equity company and our longer-term intent of
retaining the investment in the entity. During 2007, CDI determined that there
was an other than temporary impairment in its investment of Offshore Technology
Solutions Limited (“OTSL”) and the full value of CDI’s investment in OTSL was
impaired and CDI recognized equity losses of OTSL, inclusive of the impairment
charge, of $10.8 million in 2007 (Note 8).
Goodwill
and Other Intangible Assets
Under FASB Codification (“ASC”)
Topic No. 350
“Intangibles – Goodwill and Other” we are required to perform an annual
impairment analysis of goodwill and intangible assets. We elected
November 1 to be the annual impairment assessment date for goodwill and other
intangible assets. However, we could be required to evaluate the
recoverability of goodwill and other intangible assets prior to the required
annual assessment date if we experience disruption to the business, unexpected
significant declines in operating results, divestiture of a significant
component of the business, emergence of unanticipated competition, loss of key
personnel or a sustained decline in market capitalization. Our
goodwill impairment test involves a comparison of the fair value with our
carrying amount. The fair value is determined using discounted cash flows and
other market-related valuation models.
Goodwill impairment
is determined using a two-step process. The first step is to identify
if a potential impairment exists by comparing the fair value of the reporting
unit with its carrying amount, including goodwill. If the fair value
of a reporting unit exceeds its carrying amount, goodwill of the reporting unit
is not considered to have a potential impairment and the second step of the
impairment test is not necessary. However, if the carrying amount of
a reporting unit exceeds its fair value, the second step is performed to
determine if goodwill is impaired and to measure the amount of impairment loss
to recognize, if any.
The second step
compares the implied fair value of goodwill with the carrying amount of
goodwill. If the implied fair value of goodwill exceeds the carrying
amount, then goodwill is not considered impaired. However, if the
carrying amount of goodwill exceeds the implied fair value, an impairment loss
is recognized in an amount equal to that excess. The implied
fair value of goodwill is determined in the same manner as the amount of
goodwill recognized in a business combination (i.e., the fair value of the
reporting unit is allocated to all the assets and liabilities, including any
unrecognized intangible assets, as if the reporting unit had been acquired in a
business combination).
We
use both the income approach and market approach to estimate the fair value of
our reporting units under the first step. Under the income approach, a
discounted cash flow analysis is performed requiring us to make various
judgmental assumptions about future revenue, operating margins, growth rates and
discount rates. These judgmental assumptions are based on our
budgets, long-term business plans, reserve reports, economic projections,
anticipated future cash flows and market place data. Under the market
approach, the fair value of each reporting unit is calculated by applying an
average peer total invested capital EBITDA (defined as earnings before interest,
income taxes and depreciation and amortization) multiple to the upcoming fiscal
year’s budgeted EBITDA for each reporting unit. Judgment is required
when selecting peer companies that operate in the same or similar lines of
business and are potentially subject to the same corresponding economic
risks.
The continued
economic downturn and weakness in the equity and credit capital markets
continues to lead to increased uncertainty regarding the outlook of the global
economy. There were substantial commodity price declines over the
second half of 2008, with significant declines occurring in the fourth quarter
of 2008. Declines in oil and gas prices negatively impacts our
operating results and cash flow. We believe that these events
contributed to the significant decline in our stock price and corresponding
market capitalization at that time. Based on the first step of the
2008 goodwill impairment analysis, the carrying amount of two of our reporting
units exceeded their fair value as calculated under the first step, which
required us to perform the second step of the impairment test. In the
second step, the fair value of tangible and certain intangible assets was
generally estimated using discounted cash flow analysis. The fair
value of intangibles with indefinite lives such as trademark was calculated
using a royalty rate method. Based on our 2008 goodwill impairment
analysis, we recorded a $704.3 million charge to impairment expense in our Oil
and Gas segment. In addition, we eliminated all the goodwill
associated with Helix Energy Limited and its subsidiaries by recording an $8.3
million charge. We also recorded a $2.4 million charge
related to a trade name used by Helix RDS. These charges related to
Helix Energy Limited and its subsidiary, Helix RDS Limited, are
reflected as a component of income (loss) from discontinued operations in the
accompanying consolidated statements of operations. We did not record
any impairment of goodwill in 2009 based on our evaluations conducted throughout
the year. We primarily focused our goodwill evaluations on our
Well Ops SEA Pty Ltd (“WOSEA”) reporting unit’s goodwill ($15.5 million at
December 31, 2009) as its results were adversely affected by damages to their
main revenue generating asset. The asset repairs are substantially
complete and based on WOSEA’s forecasted business activity no impairment of its
goodwill was necessary during 2009.
The changes in the carrying amount
of goodwill are as follows (in thousands):
|
Contracting
Services
|
Shelf
Contracting
|
Oil
and Gas
|
Total
|
|||||||||||||
|
Balance at December 31,
2007
|
$ | 82,179 | $ | 284,141 | $ | 712,392 | $ | 1,078,712 | ||||||||
|
Impairment
expense
|
— | — | (704,311 | ) | (704,311 | ) | ||||||||||
|
Goodwill
written off related to sale of business
|
— | — | (8,081 | ) | (8,081 | ) | ||||||||||
|
Horizon
acquisition (Note 5)
|
— | 8,328 | — | 8,328 | ||||||||||||
|
Well
Ops SEA Pty Ltd. acquisition (Note 5)
|
1,029 | — | — | 1,029 | ||||||||||||
|
Other
adjustments(1)
|
(9,459 | ) | — | — | (9,459 | ) | ||||||||||
|
Balance at December 31,
2008
|
73,749 | 292,469 | — | 366,218 | ||||||||||||
|
Deconsolidation
of Cal Dive (Note 3)
|
— | (292,469 | ) | — | (292,469 | ) | ||||||||||
|
Other
adjustments(1)
|
4,894 | — | — | 4,894 | ||||||||||||
|
Balance at December 31,
2009
|
$ | 78,643 | $ | — | $ | — | $ | 78,643 | ||||||||
|
(1)
|
Reflects
foreign currency adjustment for certain amount of our
goodwill.
|
A summary of other
intangible assets, net, is as follows (in thousands):
|
As
of December 31, 2009
|
As
of December 31, 2008
|
|||||||||||||||
|
Gross
Amount
|
Accumulated
Amortization
|
Gross
Amount
|
Accumulated
Amortization
|
|||||||||||||
|
Contract backlog
|
$
|
—
|
$
|
—
|
$
|
2,960
|
$
|
(1,330
|
)
|
|||||||
|
Customer relationships
|
—
|
—
|
6,758
|
(2,294
|
)
|
|||||||||||
|
Non-compete agreements
|
1,800
|
(1,800
|
)
|
4,800
|
(4,500
|
)
|
||||||||||
|
Trade name
|
—
|
—
|
490
|
(74
|
)
(1)
|
|||||||||||
|
Intellectual property
|
1,617
|
(849
|
)
|
1,458
|
(668
|
)
|
||||||||||
|
Total
|
$
|
3,417
|
$
|
(2,649
|
)
|
$
|
16,466
|
$
|
(8,866
|
)
|
||||||
|
(1)
|
Amortization
amount reflects an impairment charge recorded to this indefinite-lived
intangible assets in fourth quarter of
2008.
|
Total amortization expenses for
intangible assets for the years ended December 31, 2009, 2008, and 2007 was $2.4
million, $5.8 million and $1.8 million, respectively. A summary of
the estimated amortization expense for the next five years is as follows (in
thousands):
|
Years
Ended December 31,
|
||||
|
2010
|
$ | 110 | ||
|
2011
|
$ | 110 | ||
|
2012
|
$ | 110 | ||
|
2013
|
$ | 110 | ||
|
2014
|
$ | 110 | ||
Recertification
Costs and Deferred Drydock Charges
Our Contracting
Services 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 costs 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 but can be as long as 60 months if the appropriate
permitting is obtained. Vessels are typically available to earn revenue for the
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 vessel’s economic useful life or functional
operating capability, are capitalized and depreciated over the vessel’s
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, 2009 and 2008, capitalized deferred drydock charges
included within Other Assets in the accompanying consolidated balance sheet
(Note 7) totaled $12.0 million and $38.6 million, respectively. During
the years ended December 31, 2009, 2008 and 2007, drydock amortization
expense was $16.4 million, $26.0 million and $23.0 million,
respectively.
Accounting
for Decommissioning Liabilities
We
account for our decommissioning liabilities in accordance with ACS Topic No. 410
“Asset
Retirement and Environmental Obligations” (“ACS 410”). 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 adjustment in the
cost estimates are reflected in the liability and the amounts continue to be
accreted over the useful life of the related long-lived asset.
ACS 410 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 exclude it from our reclamation estimates.
The following table
describes the changes in our asset retirement obligations for the year ended
2009 and 2008 (in thousands):
|
2009
|
2008
|
|||||||
|
Asset
retirement obligation at January
1,
|
$
|
225,781
|
$
|
217,479
|
||||
|
Liability
incurred during the
period
|
1,256
|
6,819
|
||||||
|
Liability
settled during the
period
|
(66,517
|
)
|
(47,703
|
)
|
||||
|
Hurricane-related
revisions in estimated cash flows
|
43,812
|
4,253
|
||||||
|
Other
revisions in estimated cash
flows
|
28,592
|
31,868
|
||||||
|
Accretion
expense (included in depreciation and amortization)
|
15,204
|
13,065
|
||||||
|
Asset
retirement obligations at December
31,
|
$
|
248,128
|
$
|
225,781
|
Revenue
Recognition
Contracting
Services Revenues
Revenues from
Contracting Services are derived from contracts that traditionally have been of
relatively short duration; however, beginning in 2007, contract durations have
started to become longer-term. 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. Further, we
record revenues net of taxes collected from customers and remitted to
governmental authorities.
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, 2009 and 2008 are expected to be billed and collected within
one year.
Dayrate
Contracts. 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 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
90
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.
Turnkey
Contracts. 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 project’s 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. If dependable estimates of progress
cannot be made or inherent hazards make such estimates doubtful, the completed
contract method is used instead of percentage-of-completion method.
A
number of our longer term pipelay contracts have been adversely affected by
delays in the delivery of the
Caesar. We believe two of our contracts qualified as
loss contracts as defined under ACS Topic No. 605.35 “Revenue
Recognition – Construction Type and Production Type
Contracts”. Accordingly, we estimate the future
shortfall between our anticipated future revenues versus future costs whenever
applicable. At December 31, 2008, we had one contract that was
expected to be completed at an estimated loss of approximately $0.8
million. We recorded this estimated loss at December 31, 2008 and the
project was completed in May 2009 at no additional loss. Under a
second contract, which was terminated, we had a potential future liability of up
to $25 million. As of December 31, 2008, we estimated the loss under
this contract at $9.0 million. In the second quarter of 2009,
services under this contract were substantially completed by a third party and
we revised our estimated loss to approximately $15.8 million. To
reflect this additional estimated loss we recorded an additional $6.8 million
charge to cost of sales in the accompanying consolidated statement of
operations. We recently agreed to settle our obligation under this
contract for $12.7 million. Accordingly we reversed $3.1 million of
our previously accrued loss under this contract to reduce it from the estimated
$15.8 million loss to $12.7 million at December 31,
2009. We have paid $7.2 million of the $12.7 million of
estimated the damages related to this terminated contact and expect to pay the
remaining $5.5 million in the second quarter of 2010.
Oil
and Gas Revenues
We
record revenues from the sales of crude oil and natural gas when delivery to the
customer has occurred, title has transferred, prices are fixed and determinable
and collection is reasonably assured. 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, 2009, the net imbalance was a
$2.5 million asset and was included in Other Current Assets
($7.6 million) and Accrued Liabilities ($5.1 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
91
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. The
deconsolidation of CDI’s net income for tax return filing purposes after its
initial public offering did not have a material impact on our consolidated
results of operations; however, because of our inability to recover our tax
basis in CDI tax free, a long term deferred tax liability is provided for any
incremental increases to the book over tax basis.
It
is our policy to provide for uncertain tax positions and the related interest
and penalties based upon management’s assessment of whether a tax benefit is
more likely than not to be sustained upon examination by tax authorities. At
December 31, 2009, we believe we have appropriately accounted for any
unrecognized tax benefits. To the extent we prevail in matters for which a
liability for an unrecognized tax benefit is established or are required to pay
amounts in excess of the liability, our effective tax rate in a given financial
statement period may be affected.
Foreign
Currency
The functional
currency for our foreign subsidiary, Helix Well Ops (U.K.) Limited is the
applicable local currency (British Pound), and the functional currency of WOSEA.
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, 2009 and 2008 and the resulting translation adjustment, which
was an unrealized (loss) gain of $30.6 million and $(71.1) million,
respectively, is included in accumulated other comprehensive income, a component
of shareholders’ equity. All foreign currency transaction gains and losses are
recognized currently in the statements of operations.
Canyon Offshore,
Inc., our ROV subsidiary, has operations in the United Kingdom and Asia Pacific.
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 each of the years ended December 31, 2009,
2008 and 2007 were not material to our results of operations or cash
flows.
Our foreign
currency gains (losses) totaled $2.2 million in 2009, $(10.0) million in 2008
and $(0.5) million in 2007.
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 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, a component of shareholders’ equity,
until the hedged transactions occur and are recognized in earnings. The
ineffective portion of a cash flow hedge’s change in fair value is recognized
immediately in earnings. In addition, any change in the fair value of a
derivative that does not qualify for hedge accounting is recorded in earnings in
the period in which the change occurs. Further, when we have
obligations and receivables with the same counterparty, the fair value of the
derivative liability and asset are presented at net value.
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 our hedging transactions are highly effective in
offsetting changes in cash flows of the 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 if it is probable the forecasted
transaction will not occur. If the forecasted transaction continues to be
probable of occurring any deferred gains or losses in accumulated
other comprehensive income are amortized to earnings over the remaining period
of the original forecasted transaction.
Commodity
Price Risks
The fair value of
derivative 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. These
modeling techniques require us to make estimations 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.
We
have entered into various costless collar and swap contracts to stabilize cash
flows relating to a portion of our expected oil and gas production. These
contracts qualified for hedge accounting. However, due to disruptions in our
production as a result of damages caused by the hurricanes in third quarter
2008, most of our 2009 natural gas financial contracts no longer qualified for
hedge accounting as of March 31, 2009. At their inception, our
forward sales contracts qualified for the normal purchases and sales scope
exception but due to disruptions in our production as a result of damages
caused by the 2008 hurricanes these contracts ceased to qualify for
the scope exception.
The aggregate fair value of our
commodity derivative instruments were a net asset (liability) of
$(14.5) million and $22.3 million as of December 31, 2009 and
2008, respectively. For the years ended December 31, 2009, 2008
and 2007, we recorded unrealized gains (losses) of approximately
$14.5 million, $14.9 million and $(8.1) million, net of tax
expense (benefit) of $(5.1) million, $5.2 million and
$(2.8) million, respectively, in accumulated other comprehensive income, a
component of shareholders’ equity. During 2009, 2008 and 2007, we
reclassified approximately $17.0 million, $(23.4) million and $0.5 million,
respectively, of gains (losses) from other comprehensive income to Oil and Gas
revenues upon the sale of the related oil and gas production. In
addition, during 2009 and 2008 we recorded a gains of approximately
$89.5 million and $21.6 million, respectively, to reflect
mark-to-market adjustments for changes in the fair values of our contracts that
no longer qualified for hedge accounting. These gains are reported in
the accompanying consolidated statements of operations in the line titled “Gain
on oil and gas derivative commodity contracts”. At the end of 2009
and 2007 all contracts qualified for hedge
accounting.
As
of December 31, 2009, we have the following volumes under derivatives and
forward sales contracts related to our oil and gas producing activities totaling
approximately 2.5 million barrels of oil and 25 Bcf of natural gas:
|
Production
Period
|
Instrument
Type
|
Average
Monthly
Volumes
|
Weighted
Average
Price
|
|||
|
Crude
Oil:
|
(per
barrel)
|
|||||
|
January 2010 — December
2010
|
Collar
|
|
100
MBbl
|
$62.50-$80.73
|
||
|
January 2010 — December
2010
|
Swap
|
77.1 MBbl
|
$76.99
|
|||
|
January 2010 — June 2010
|
Swap
|
50
MBbl
|
$71.08
|
|||
|
July
2010 — December
2010
|
Swap
|
15
MBbl
|
$74.07
|
|||
|
Natural
Gas:
|
(per
Mcf)
|
|||||
|
January 2010 — December
2010
|
Swap
|
1,079.2
Mmcf
|
$5.82
|
|||
|
January 2010 — December
2010
|
Collar
|
1,003.8
Mmcf
|
$6.00 — $6.70
|
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 with the
change in NYMEX prices.
Variable
Interest Rate Risks
As
the interest rates for some of our long-term debt are subject to market
influences and will vary over the term of the debt, we entered into various
interest rate swaps to stabilize cash flows relating to a portion of our
interest payments on our variable interest rate debt. Changes in the
interest rate swap fair value are deferred to the extent the swap is effective
and are recorded as a component of accumulated other comprehensive income until
the anticipated interest payments occur and are recognized in interest
expense. The ineffective portion of the interest rate swap, if any, will
be recognized immediately in earnings.
In
September 2006, we entered into various interest rate swaps to stabilize cash
flows relating to a portion of our interest payments on our Term Loan (Note
10). These interest rate swaps qualified for hedge
accounting. On December 21, 2007, we prepaid a portion of our Term
Loan which reduced the notional amount of our interest rate swaps and caused our
hedges to become ineffective. As a result, the interest rate swaps no
longer qualified for hedge accounting treatment under SFAS No. 133. On January
31, 2008, we re-designated these swaps as cash flow hedges with respect to our
outstanding LIBOR-based debt; however, at September 30, 2008, based on the
hypothetical derivatives method, we assessed the hedges were not highly
effective, and as such, no longer qualified for hedge accounting. During the
year ended December 31, 2008 and 2007, we recognized $5.3 million and $0.6
million, respectively, of unrealized losses as other expense as a result of the
change in fair value of our interest rate swaps. As of December 31,
2008 and December 31, 2007, the aggregate fair value of the derivative
instruments was a net liability of $8.0 million and $4.7 million,
respectively. During the year
ended December 31, 2008 and 2007, we reclassified approximately $1.7 million and
$(0.4) million of (gains) losses, respectively, from other accumulated
comprehensive income (loss), a component of shareholders’ equity, to
interest expense. The last of the 2006 interest
rate swaps were settled in October 2009.
In January 2010, we entered into
$200 million, two year interest rate swaps to stabilize cash flows relating to a
portion of our interest payments on our Term Loan (Note 10).
Foreign
Currency Exchange Risks
Because we operate
in various regions in the world, we conduct a portion of our business in
currencies other than the U.S. dollar. We entered into various
foreign currency forwards to stabilize expected cash outflows relating to
certain shipyard contracts where the contractual payments are denominated in
euros and expected cash outflows relating to certain vessel charters
denominated in British pounds. The aggregate fair value of the
foreign currency forwards as of December 31, 2009 and December 31, 2008 was a
net asset (liability) of $2.1 million and $(0.9) million,
respectively. For the year ended December 31, 2008
we recorded unrealized gains of approximately $0.1 million in accumulated
other comprehensive income, a component of shareholders’ equity, all of which
were reclassified into earnings in 2009. All our remaining foreign exchange
contracts are not accounted for as hedge contracts and changes in their fair
value are being marked to market each reporting period. In 2009
we recorded gains totaled $3.3 million associated with foreign exchange
contracts not qualifying for hedge accounting compared with a $1.1 million loss
in 2008. See Note 22 for more information regarding our foreign
currency contracts.
Earnings
Per Share
Effective on
January 1, 2009, ASC Topic No. 260 “Earnings
Per Share” provided for the adoption of the requirements under the former
FSP No. EITF 03-06-1, “Determining
Whether Instruments Granted in Share Based Payment Transactions Are
Participating Securities.” We have shares of restricted stock
issued and outstanding, some of which remain subject to certain vesting
requirements. Holders of such shares of unvested restricted
stock are entitled to the same liquidation and dividend rights as the holders of
our outstanding common stock and are thus considered participating
securities. Under
this applicable accounting guidance, the undistributed earnings for each period
are allocated based on the contractual participation rights of both the common
shareholders and holders of any participating securities as if earnings for the
respective periods had been distributed. Because both the liquidation
and dividend rights are identical, the undistributed earnings are allocated on a
proportionate basis. Further, we are required to compute EPS amounts
under the two class method.
Basic earnings per
share ("EPS") is computed by dividing the undistributed 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
that 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, 2009, 2008 and
2007 were as follows (in thousands):
|
Year
Ended December 31,
|
|||||||||||||||
|
2009
|
2008
|
2007
|
|||||||||||||
|
Income
|
Shares
|
Income
|
Shares
|
Income
|
Shares
|
||||||||||
|
Basic:
|
|||||||||||||||
|
Net income
applicable to common shareholders
|
$ | 101,867 | $ | (639,122 | ) | $ | 311,982 | ||||||||
|
Less:
Undistributed net income allocable to participating
securities
|
(1,436 | ) |
─
|
(4,189 | ) | ||||||||||
|
Undistributed
net income applicable to common shareholders
|
100,431 | (639,122 | ) | 307,793 | |||||||||||
|
(Income) loss
from discontinued operations
|
(9,581 | ) | 9,812 | (1,347 | ) | ||||||||||
|
Add:
Undiscounted net income from discontinued operations allocable to
participating securities
|
135 |
─
|
18 | ||||||||||||
|
Income (loss)
per common share – continuing operations
|
$ | 90,985 |
99,136
|
$ | (629,310 | ) |
90,650
|
$ | 306,464 |
90,086
|
|||||
|
Year
Ended December 31,
|
||||||||||||||||||||||||
|
2009
|
2008
|
2007
|
||||||||||||||||||||||
|
Income
|
Shares
|
Income
|
Shares
|
Income
|
Shares
|
|||||||||||||||||||
|
Diluted:
|
||||||||||||||||||||||||
|
Net income
per common share –
continuing operations –
Basic
|
$
|
90,985
|
99,136
|
$
|
(629,310
|
)
|
90,650
|
$
|
306,464
|
90,086
|
||||||||||||||
|
Effect of
dilutive securities:
|
||||||||||||||||||||||||
|
Stock options
|
─
|
28
|
─
|
─
|
─
|
382
|
||||||||||||||||||
|
Undistributed
earnings reallocated to participating securities
|
80
|
─
|
─
|
─
|
239
|
─
|
||||||||||||||||||
|
Convertible Senior Notes
|
─
|
─
|
─
|
─
|
─
|
1,548
|
||||||||||||||||||
|
Convertible preferred
stock
|
748
|
6,556
|
─
|
─
|
3,716
|
3,631
|
||||||||||||||||||
|
Income (loss)
per common share ─
continuing operations
|
91,813
|
(629,310
|
)
|
310,419
|
||||||||||||||||||||
|
Income (loss)
per common share─ discontinued operations
|
9,581
|
(9,812
|
)
|
1,347
|
||||||||||||||||||||
|
Net income per common
share
|
$
|
101,394
|
105,720
|
$
|
(639,122
|
)
|
90,650
|
$
|
311,766
|
95,647
|
||||||||||||||
The cumulative
$53.4 million of beneficial conversion charges that were realized and recorded
during the first quarter of 2009 following the transaction affecting our
convertible preferred stock (Note 12) are not included as an addition to adjust
earnings applicable to common stock for our diluted earnings per share
calculation.
We
had a net loss applicable to common shareholders in
2008. Accordingly, our diluted per share calculation for 2008 was
equivalent to our basic loss per share calculation because it excluded any
assumed exercise or conversion of common stock equivalents because they were
deemed to be anti-dilutive, meaning their inclusion would have reduced the
reported net loss per share for 2008. Shares that otherwise
would have been included in the diluted per share amount included 0.3
million shares associated with stock options for which the exercise price was
less than the average price of our common stock for 2008, 0.1 million shares
associated with unvested restricted shares and 3.6 million equivalent shares of
common stock from the assumed conversion of our convertible preferred
stock. The diluted earnings (loss) per share calculation also
excluded the consideration of adding back the $3.2 million of dividends and
related costs associated with the convertible preferred stock that otherwise
would have been added back to net income if assumed conversion of the shares was
dilutive during 2008. There were no stock options outstanding for
which the exercise price was greater than the average price of our common stock
for each of the years ending December 31, 2008 and 2007.
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
95
business day prior
to the grant date, and expense was recognized over the vesting period of each
grant on a straight-line basis.
We
did not grant any stock options during the three-year period ended December 31,
2009. The fair value of shares issued under the Employee Stock Purchase Plan was
based on the 15% discount received by the employees. The estimated fair value of
the options is amortized to 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 or issuance 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 CDI’s initial public offering and common
stock issuance as part of the acquisition of Horizon Offshore, Inc.
(“Horizon”). Effective January 1, 2009, we have changed our
accounting policy of recognizing a gain or loss upon any future direct sale or
issuance of equity by our subsidiaries if the sales price differs from our
carrying amount to be in accordance with recently issued accounting
requirements, in which a gain or loss will only be recognized when loss of
control of a consolidated subsidiary occurs. See “New Accounting Standards”
below and Note 3.
Consolidation
of Variable Interest Entities
ASC Topic No. 810
“Consolidation” requires consolidation of variable interest entities in which an
enterprise absorbs a majority of the entity’s expected losses, receives a
majority of the entity’s expected residual returns, or both, as a result of
ownership, contractual or other financial, interests in the entity.
Fair
Value of Financial Instruments
Our financial
instruments consist of cash and cash equivalents, accounts receivable, accounts
payable and our long-term debt. The carrying amount of cash and cash
equivalents, accounts receivable and accounts payable approximates fair value
due to the highly liquid nature of these instruments. The carrying amount and
estimated fair value of our debt, including current maturities as of
December 31, 2009 and 2008 follow (amount in thousands):
|
2009
|
2008
|
|||||||||||||||
|
Carrying
Value
|
Fair
Value
|
Carrying
Value
|
Fair
Value
|
|||||||||||||
|
Term Loan(1)
|
$ | 414,766 | $ | 397,138 | $ | 419,093 | $ | 251,455 | ||||||||
|
Revolving Credit Facility(2)
|
─
|
─
|
349,500 | 349,500 | ||||||||||||
|
Cal Dive Term Loan(2),
(3)
|
─
|
─
|
315,000 | 315,000 | ||||||||||||
|
Convertible Senior Notes(1)
|
273,064 | 271,791 | 265,184 | 136,383 | ||||||||||||
|
Senior Unsecured Notes(1)
|
550,000 | 563,750 | 550,000 | 261,250 | ||||||||||||
|
MARAD Debt(4)
|
119,235 | 123,730 | 123,449 | 132,609 | ||||||||||||
|
Loan Notes(5)
|
3,674 | 3,674 | 5,000 | 5,000 | ||||||||||||
|
Total
|
$ | 1,360,739 | $ | 1,360,083 | $ | 2,027,226 | $ | 1,451,197 | ||||||||
|
(1)
|
The fair
values of these instruments were based on quoted market prices as of
December 31, 2009 and 2008. The fair values were estimated
using level 1 inputs using the market approach (see “Recently Issued
Accounting Principles” below).
|
|
(2)
|
The carrying
values of these credit facilities approximate fair
value.
|
|
(3)
|
We
deconsolidated Cal Dive from our financial statements in June 2009
following the sale of a substantial amount of our remaining ownership
interest in Cal Dive (Note 3).
|
|
(4)
|
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. The fair value of the MARAD
debt was estimated using Level 2 fair value inputs using the cost approach
(see “Recently Issued Accounting Principles” below).
|
|
(5)
|
The carrying
value of the loan notes approximates fair value as the maturity date of
the loan notes is 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 spend capital on exploration, drilling and production
operations expenditures, the amount of which is generally dependent on the
prevailing view of future oil and gas prices that are subject to many external
factors which may contribute to significant volatility in future prices. Our
customers consist primarily of major oil and gas companies, 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, those whose total represented 10% or
more of our consolidated revenues, was as follows: 2009 — Shell Offshore,
Inc. (12%); 2008 — Louis Dreyfus Energy Services (10%) and Shell Offshore,
Inc. (12%) and 2007 — Louis Dreyfus Energy Services (14%) and Shell
Offshore, Inc. (10%). All of these customers were purchasers of our oil and gas
production. We estimate that in 2009 we provided subsea services to over 200
customers.
New
Accounting Standards
In
September 2006, the FASB issued fair value accounting rules now included within
ASC Codification Topic No. 820 “Fair
Value Measurements and Disclosures” (ASC 820). We adopted the
provisions of ASC 820 on January 1, 2008 for assets and liabilities not
subject to the deferral and adopted this standard for all other assets and
liabilities on January 1, 2009. The adoption of ASC 820 had an
immaterial impact on our results of operations, financial condition and
liquidity.
ASC 820, among
other things, defines fair value, establishes a consistent framework for
measuring fair value and expands disclosure for each major asset and liability
category measured at fair value on either a recurring or nonrecurring basis. ASC
820 clarifies that fair value is an exit price, representing the amount that
would be received to sell an asset, or paid to transfer a liability, in an
orderly transaction between market participants. These fair value accounting
rules establish a three-tier fair value hierarchy, which prioritizes
the inputs used in measuring fair value as follows:
|
•
|
Level
1. Observable inputs such as quoted prices in active
markets;
|
||
|
•
|
Level
2. Inputs, other than the quoted prices in active markets, that
are observable either directly or indirectly; and
|
||
|
•
|
Level 3.
Unobservable inputs for which there is little or no market data, which
require the reporting entity to develop its own
assumptions.
|
Assets and
liabilities measured at fair value are based on one or more of three valuation
techniques noted. The valuation techniques are as follows:
|
(a)
|
Market
Approach. Prices and other relevant information generated by
market transactions involving identical or comparable assets or
liabilities.
|
|
(b)
|
Cost
Approach. Amount that would be required to replace the
service capacity of an asset (replacement
cost).
|
|
(c)
|
Income
Approach. Techniques to convert expected future cash flows to a single
present amount based on market expectations (including present value
techniques, option-pricing and excess earnings
models).
|
The following table
provides additional information related to assets and liabilities measured at
fair value on a recurring basis at December 31, 2009 (in
thousands):
|
Level
1
|
Level
2
|
Level
3
|
Total
|
Valuation
Technique
|
||||||||||||||||
|
Assets:
|
||||||||||||||||||||
|
Oil
and gas swaps and collars
|
$
|
–
|
$
|
5,071
|
$
|
–
|
$
|
5,071
|
(c)
|
|||||||||||
|
Foreign
currency forwards
|
–
|
2,074
|
–
|
2,074
|
(c)
|
|||||||||||||||
|
Investment
in Cal Dive (Note 3)
|
3,780
|
–
|
–
|
3,780
|
(a)
|
|||||||||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Oil
and gas swaps and collars
|
–
|
19,536
|
–
|
19,536
|
(c)
|
|||||||||||||||
|
Fair
value of long term debt
|
1,236,353
|
123,730
|
–
|
1,360,083
|
(a),(b)
|
|||||||||||||||
|
Total
|
$
|
1,232,573
|
$
|
136,121
|
$
|
–
|
$
|
1,368,694
|
On
June 30, 2009, we adopted the fair value standards within ASC Topic
820-10-65-4. These standards provide additional guidance for estimating fair
value when the volume and level of activity for the asset or liability have
significantly decreased and includes guidance for identifying circumstances that
indicate a transaction is not orderly. This guidance is necessary to maintain
the overall objective of fair value measurements, which is that fair value is
the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date under current market conditions. The adoption of these
standards had no impact on our results of operations, cash flows and financial
condition.
On
January 1, 2009, we adopted the revised standards for business combinations
contained in ASC Topic 805 “Business Combinations.” These
standards now require the acquiring entity in a business combination to
recognize all the assets acquired and liabilities assumed in the transaction,
establishes the acquisition-date fair value as the measurement objective for all
assets acquired and liabilities assumed, and requires the acquirer to disclose
to investors and other users all of the information they need to evaluate and
understand the nature and financial effect of the business combination. It also
requires that the costs incurred related to the acquisition be charged to
expense as incurred, when previously these costs were capitalized as part of the
acquisition cost of the asset or business. The adoption of these new
standards had no impact on our results of operations, cash flows and financial
condition.
On
January 1, 2009 we adopted the financial requirements of ASC
810-10-65-1 “Consolidation
Transition.” These
standards were enacted to improve the relevance, comparability, and transparency
of financial information provided to investors by requiring all entities to
report noncontrolling (minority) interests in subsidiaries as equity in the
consolidated financial statements. These standards were required to be adopted
prospectively, except the following provisions were required to be
adopted retrospectively:
|
1.
|
Reclassifying
noncontrolling interest from the “mezzanine” to equity, separate from the
parents’ shareholders’ equity, in the statement of financial position;
and
|
|
2.
|
Recasting
consolidated net income to include net income attributable to both the
controlling and noncontrolling interests. That is,
retrospectively, the noncontrolling interests’ share of a consolidated
subsidiary’s income should not be presented in the income statement as
“minority interest.”
|
Effective January
1, 2009, we changed our accounting policy of recognizing a gain or loss upon any
future direct sale or issuance of equity by our subsidiaries if the sales price
differs from our carrying amount, in which a gain or loss will only be
recognized when loss of control of a consolidated subsidiary occurs. See Note 3
for disclosure of stock sales transactions that ultimately resulted in our loss
of control of CDI.
On
January 1, 2009 we adopted certain financial accounting standards included with
ASC Topic No. 815 “Derivatives
and Hedging.” These standards apply to all derivative instruments and
related hedged items and require that entities provide qualitative disclosures
about the objectives and strategies for using derivatives, quantitative data
about the fair value of and gains and losses on derivative contracts, and
details of credit-risk-related contingent features in their hedged
positions. Adoption of these standards had no impact on our
results of operations, cash flows or financial condition. See Note 22
below for the required disclosures for our derivative
instruments.
Effective January 1, 2009, we
adopted accounting standards as required in ASC Topic No. 470-20 “Debt
with Conversion and Other Options.” These standards require retrospective
application for all periods reported (with the cumulative effect of the change
reported in retained earnings as of the beginning of the first period
presented). These standards require the proceeds from the issuance of
convertible debt instruments to be allocated between a liability component
(issued at a discount) and an equity component. The resulting debt discount is
amortized over the period the convertible debt is expected to be outstanding as
additional non-cash interest expense. This standard affects the
accounting treatment for our Convertible Senior Notes and increases our interest
expense for our past and future reporting periods by recognizing accretion
charges on the resulting debt discount.
Upon adoption, we recorded a
discount of $60.2 million related to our Convertible Senior Notes. To
arrive at this discount amount we estimated the fair value of the liability
component of the Convertible Senior Notes as of the date of their issuance
(March 30, 2005) using an income approach. To determine this
estimated fair value, we used borrowing rates of similar market transactions
involving comparable liabilities at the time of issuance and an expected life of
7.75 years. In selecting the expected life, we selected the earliest
date that the holder could require us to repurchase all or a portion of the
Convertible Senior Notes (December 15, 2012).
On
June 30, 2009, we adopted the general standards of accounting for and
disclosures of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. Specifically, ASC
Topic No. 855 “Subsequent
Events” sets forth the period after the balance sheet date during which
management of a reporting entity should evaluate events or transactions that may
occur for potential recognition or disclosure in the financial statements, the
circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date in its financial statements, and the
disclosures that an entity should make about events or transactions that
occurred after the balance sheet date. The adoption of these
standards had no impact on our results, cash flow or financial
position as management already followed a similar approach prior to the adoption
of this standard.
In
December 2008, the SEC announced that it had approved revisions designed to
modernize the oil and gas company reserve reporting
requirements. In January 2010, the FASB issued Accounting
Standards Update 2010-03 “Oil
and Gas Reserve Estimation and Disclosures.” For our reserve
estimates at year end 2009, we have implemented the newly mandated authoritative
guidance issued by the FASB on extractive activities for oil and gas reserves
estimation and disclosures. The objective of the new guidance
is to align the oil and gas reserve estimation and disclosure requirements with
the requirements of the SEC. The most significant amendments to
the requirements included the following.
|
·
|
Commodity
prices - estimates of proved reserves and related discounted
cash flows now based on an average twelve month commodity price based on
the price of oil and gas on the first day of each month for the year the
reserve report relates;
|
|
·
|
Disclosure of
Unproved Reserves - Probable and Possible reserves may be
disclosed separately from proved reserves on a voluntary basis. We elected
not to disclose Probable and Possible
reserves;
|
|
·
|
Proved
Undeveloped Reserve Guidelines – Reserves may be classified as proved
undeveloped reserves if there is a high degree of confidence that the
quantities will be recovered and they are scheduled to be drilled within
the next five years, unless specific circumstances justify a longer
time;
|
|
·
|
Reserves
Estimation Using New Techniques – Reserves may be estimated through a use
of reliable techniques in addition to traditional flow test and production
history;
|
|
·
|
Reserves
Personnel and Estimation Process – Additional disclosure is required
regarding the qualifications of the chief technical person who oversees
the reserve estimation process and/or the independence of the preparer of
our estimated proved reserves. We must also disclose our significant
internal controls over the reserve estimation
process;
|
|
·
|
Disclosure by
Geographic Area – Reserves in foreign countries must be presented
separately if such reserves represent more than 15% of our total estimated
oil and gas proved reserves; and
|
|
·
|
Non
Traditional Resources- The definition of oil and gas producing activities
has been expanded to include other marketable
products.
|
Note 3 —
Ownership of Cal Dive International, Inc.
In
December 2006, we contributed the assets of our Shelf Contracting segment into
Cal Dive, our then wholly owned subsidiary. Cal Dive subsequently sold
approximately 22.2 million 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 December 2006, Cal Dive borrowed $201 million under its
credit facility and distributed $200 million of the proceeds to us as a
dividend. We recognized an after-tax gain of $96.5 million, net
of taxes of $126.6 million as a result of these transactions. We used 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% as of December 31, 2006.
Our ownership in CDI was further reduced in December 2007 as a result of CDI’s
stock issuance related to the its acquisition of Horizon Offshore
Inc. Our ownership in CDI as of December 31, 2008 was
approximately 57.2%.
In
January 2009, we sold approximately 13.6 million shares of Cal Dive common stock
to Cal Dive for $86 million. This transaction constituted a single
transaction and was not part of any planned set of transactions that would
result in us having a noncontrolling interest in Cal Dive, and reduced our
ownership in Cal Dive to approximately 51%. Because we retained
control of CDI immediately after the transaction, the loss of approximately $2.9
million on this sale was treated as a reduction of our equity in the
accompanying condensed consolidated balance sheet.
In
June 2009, we sold 22.6 million shares of Cal Dive common stock held by us
pursuant to a secondary public offering (“Offering”). Proceeds from
the Offering totaled approximately $182.9 million, net of underwriting
fees. Separately, pursuant to a Stock Repurchase Agreement with Cal
Dive, simultaneously with the closing of the Offering, Cal Dive
99
repurchased
from us approximately 1.6 million shares of its common stock for net proceeds of
$14 million at $8.50 per share, the Offering price. Following the closing of
these two transactions, our ownership of Cal Dive common stock was reduced to
approximately 26%.
Because these
transactions reduced our ownership in Cal Dive to less than 50%, the $59.4
million gain resulting from the sale of these shares was reflected in “Gain on
sale of Cal Dive common stock” in the accompanying consolidated statement of
operations. The $59.4 million amount included an approximate $27.1
million gain associated with the re-measurement of our remaining 26% ownership
interest in Cal Dive at its fair value on June 10, 2009, the date of the closing
of the Offering, which represented the date of
deconsolidation. Since we no longer held a controlling interest
in Cal Dive, we ceased consolidating Cal Dive effective June 10, 2009, and
subsequently accounted for our remaining ownership interest in Cal Dive under
the equity method of accounting until September 23, 2009, as further discussed
below.
On
September 23, 2009, we sold 20.6 million shares of Cal Dive common stock held by
us pursuant to a second secondary public offering (“Second
Offering”). On September 24, 2009, the underwriters sold
an additional 2.6 million shares of Cal Dive common stock held by us pursuant to
their overallotment option under the terms of the Second
Offering. The price for the Second Offering was $10 per share,
with resulting proceeds totaling approximately $221.5 million, net of
underwriting fees. We recorded an approximate $17.9 million gain
associated with the Second Offering transactions.
Following the
closing of the Second Offering transactions, we own 0.5 million shares of Cal
Dive common stock, representing less than 1% of the total outstanding
shares of Cal Dive. Accordingly we now classify our remaining
interest in Cal Dive as an investment available for sale pursuant to ASC Topic
No. 320 “Investment -
Debt and Equity Securities.” As an investment available for
sale, the value of our remaining interest will be marked-to-market at each
period end with the corresponding change in value being reported as a component
of other comprehensive income (loss) in the accompanying consolidated balance
sheet at December 31, 2009 (Note 14). We intend to sell our remaining
shares of Cal Dive common stock over the near term. The value of our
remaining investment in Cal Dive decreased by $1.3 million from the closing of
the Second Offering to December 31, 2009.
Proceeds from our
Cal Dive stock sale transaction were used for general corporate
purposes.
Note
4 – Insurance Matters
In
September 2008, we sustained damage to certain of our facilities resulting from
Hurricane Ike. All
of our segments were affected by the hurricane; however, the oil and gas segment
suffered the substantial majority of our aggregate damages. While we
sustained damage to our own production facilities from Hurricane Ike,
the larger issue in terms of our production recovery involved damage to third
party pipelines and onshore processing facilities. The timing of the
repairs of these facilities was not subject to our control. One
significant third party pipeline was not repaired and placed back into service
until January 2010. Our insurance policy, which covered all of our operated and
non-operated producing and non-producing properties, was subject to an
approximate $6 million of aggregate deductibles. We met our aggregate
deductible in September 2008. We record our hurricane-related repair
costs as incurred in our oil and gas cost of sales. We record
insurance reimbursements when the realization of the claim for recovery of a
loss is deemed probable.
In
June 2009, we reached a settlement with the underwriters of our insurance
policies related to damages from Hurricane Ike. Insurance
proceeds received in the second quarter of 2009 totaled $102.6
million. Previously, we had received approximately $25.6 million of
reimbursements under previously submitted Ike-related
insurance claims. In the second quarter of 2009, we recorded a $43.0
million net reduction in our cost of sales in the accompanying
condensed consolidated statements of operations representing the amount our
insurance recoveries exceeded our costs during the second quarter of
2009. The cost reduction reflected the net proceeds of
$102.6 million partially offset by $8.1 million of hurricane-related expenses
incurred in the second quarter of 2009 and $51.5 million of hurricane related
impairment charges, including $43.8 million of additional estimated asset
retirement costs (“ARO”) resulting from additional work performed and/or further
evaluation of facilities on properties that were classified as a “total loss”
following the storm.
We
are substantially complete with our hurricane repairs; however we are still
incurring costs related to our accrued asset retirement
obligations.
The following table summarizes the
claims and reimbursements by segment that affected our costs of sales accounts
under various insurance claims resulting from damages sustained by Hurricane
Ike,
primarily those claims and reimbursements recently settled under our energy
insurance policy (in thousands):
|
Year
Ended
December
31,
2009
|
Since
Inception in September 2008
|
|||||||
|
Oil and
gas:
|
||||||||
|
Hurricane
repair
costs
|
$ | 25,788 | $ | 48,339 | ||||
|
ARO
liability adjustments
|
43,812 | 48,065 | ||||||
|
Hurricane-related
impairments
|
7,699 | 37,597 | ||||||
|
Insurance
recoveries (1)
|
(100,874 | ) | (118,415 | ) | ||||
|
Net
(reimbursements) costs
|
$ | (23,575 | ) | $ | 15,586 | |||
|
Contracting
services:
|
||||||||
|
Hurricane
repair
costs
|
$ | 776 | $ | 6,026 | ||||
|
Insurance
recoveries
|
(2,885 | ) | (5,022 | ) | ||||
|
Net
(reimbursements) costs
|
(2,109 | ) | 1,004 | |||||
|
Shelf Contracting (2):
|
||||||||
|
Hurricane
repair
costs
|
$ | 613 | $ | 4,550 | ||||
|
Insurance
recoveries
|
(2,849 | ) | (5,183 | ) | ||||
|
Net
reimbursements
|
$ | (2,236 | ) | (633 | ) | |||
|
Totals:
|
||||||||
|
Hurricane
repair
costs
|
$ | 27,177 | $ | 58,915 | ||||
|
ARO
liability adjustments
|
43,812 | 48,065 | ||||||
|
Hurricane-related
impairments
|
7,699 | 37,597 | ||||||
|
Insurance
recoveries
|
(106,608 | ) | (128,620 | ) | ||||
|
Net
(reimbursements) costs
|
$ | (27,920 | ) | $ | 15,957 | |||
|
(1)
|
Recoveries
include reimbursements for capital items totaling $0.2 million in 2009 and
$13.2 million in 2008.
|
|
(2)
|
Includes
amount prior to deconsolidation of Cal Dive in June 2009 (Note
3).
|
We
renewed our energy and marine insurance for the period July 1, 2009 to June 30,
2010. However, this insurance renewal did not include wind storm
coverage as the premium and deductibles would have been relatively substantial
for the underlying coverage provided. In order to mitigate potential
loss with respect to our most significant oil and gas properties from hurricanes
in the Gulf of Mexico, we entered into a weather derivative (Catastrophic
Bond). The Catastrophic Bond provides for payments of
negotiated amounts should the eye of a Category 3 or greater hurricane pass
within certain pre-defined areas encompassing our more prominent oil and gas
producing fields. The premium for this Catastrophic Bond was
approximately $13.1 million. The Catastrophic Bond is not
considered a risk management instrument for accounting
purposes. Accordingly, the premium associated with the
Catastrophic Bond is not charged to expense on a straight line basis as
customary with insurance premiums, but rather it is charged to expense on a
basis to reflect the Catastrophic Bond’s intrinsic value at the end of the
period. Because our Catastrophic Bond was underwritten to mitigate
the risk of hurricanes in the Gulf of Mexico, substantially all of its intrinsic
value is for the period associated with “hurricane season” (typically June 1 to
November 30) with a substantial majority of the intrinsic value associated with
the period July 1, 2009 to September 30, 2009. As a result, we
charged to expense $10.4 million of our $13.1 premium in the third quarter of
2009 and $2.4 million of premium was charged to expense in the fourth quarter of
2009. The remaining $0.3 million will be charged to expense over
first half of 2010. The expense associated with the Catastrophic Bond
premium is recorded as a component of lease operating expense for our oil and
gas operations.
Note 5 —
Acquisitions
Well
Ops SEA Pty Ltd.
In
October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (“Seatrac”) for
total consideration of approximately $12.7 million (including $0.2 million
of transaction costs), with approximately $9.1 million paid to existing
Seatrac shareholders and $3.4 million for subscription of new Seatrac
shares. We renamed this entity Well Ops SEA Pty Ltd. (“WOSEA”). WOSEA is a
subsea well intervention and engineering services company located in Perth,
Australia. On July 1, 2007, we exercised an option to purchase the
remaining 42% of WOSEA for approximately $10.1 million. This purchase was
accounted for as a business combination with the acquisition price allocated to
the assets acquired and liabilities assumed based upon their estimated fair
value, with the excess being recorded as goodwill. The following table
summarizes the estimated fair values of the assets acquired and liabilities
assumed at July 1, 2007 (in thousands):
|
Cash and cash
equivalents
|
$
|
2,631
|
||
|
Other current
assets
|
4,279
|
|||
|
Property and
equipment
|
9,571
|
|||
|
Goodwill
|
11,328
|
|||
|
Total
assets
acquired
|
$
|
27,809
|
||
|
Accounts
payable and accrued
liabilities
|
$
|
5,059
|
||
|
Net
assets
acquired
|
$
|
22,750
|
Pro forma combined
operating results for the years ended December 31, 2007 (adjusted to
reflect the results of operations of WOSEA prior to its acquisition) are not
provided because the pre-acquisition results related to WOSEA were not material
to the historical results of the Company.
In
February 2010, we announced the formation of a joint venture with
Australian-based engineering and construction company, Clough Limited, to
provide a range of subsea services to offshore operators in the Asia Pacific
region. Services provided by the joint venture, named CloughHelix Pty Ltd., will
include subsea well intervention and well abandonment, SURF (subsea
infrastructure, umbilical, riser and flowline installation), saturation and air
diving and subsea inspection, repair and maintenance services. The
CloughHelix joint venture will integrate our well intervention equipment with
Clough’s new 12 man saturation diving system, to enable both to be deployed from
the 118 meter long DP2 multiservice vessel, Normand Clough, outfitted with a 250
ton active heave compensated crane.
Note 6 —
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, 2009, we had capitalized costs associated with ongoing
exploration and/or appraisal activities totaling $3.1 million. In the
fourth quarter of 2008, we charged the $18.6 million of costs associated with
the Huey and Castleton exploration wells to dry hole exploration expense, when
it became unlikely that we would pursue additional development of these
wells. Other 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, 2009
and 2008 (in thousands):
|
2009
|
2008
|
|||||||
|
Wang (1)
|
$
|
2,934
|
$
|
1,545
|
||||
|
Other
|
125
|
560
|
||||||
|
Total
|
$
|
3,059
|
$
|
2,105
|
|
(1)
|
Amounts include
pre-engineering and limited capital items. Prospect is
located in proximity of our Phoenix field, which is expected to commence
production around mid-year 2010. Drilling of Wang is a
discretionary capital item for 2010 but we expect exploration of this
prospect will occur over the near
term.
|
The following table
reflects net changes in suspended exploratory well costs during the year ended
December 31, 2009, 2008 and 2007 (in thousands):
|
2009
|
2008
|
2007
|
||||||||||
|
Beginning
balance at January
1,
|
$
|
2,105
|
$
|
19,096
|
$
|
49,983
|
||||||
|
Additions
pending the determination of proved reserves
|
36,208
|
2,305
|
213,699
|
|||||||||
|
Reclassifications
to proved
properties
|
(34,622
|
)
|
(463
|
)
|
(234,277
|
)
|
||||||
|
Charged to
dry hole
expense
|
(632
|
)
|
(18,833
|
)
|
(10,309
|
)
|
||||||
|
Ending
balance at December
31,
|
$
|
3,059
|
$
|
2,105
|
$
|
19,096
|
Further, the
following table details the components of exploration expense for the years
ended December 31, 2009, 2008 and 2007 (in thousands):
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Delay rental and geological
and geophysical costs
|
$
|
3,016
|
$
|
5,223
|
$
|
6,538
|
||||||
|
Impairment of unproved
properties
|
20,130
|
8,870
|
9,878
|
|||||||||
|
Dry hole expense
|
1,237
|
18,833
|
10,309
|
|||||||||
|
Total
exploration expense
|
$
|
24,383
|
$
|
32,926
|
$
|
26,725
|
||||||
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
$26.8 million, $66.3 million and $57.1 million for the years
ended December 31, 2009, 2008 and 2007, 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.
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 suspension of production (“SOP”) approval from the MMS. Following
the acquisition of the Typhoon oil field and MMS approval, we renamed the field
Phoenix. We expect to deploy a minimal floating production system in 2010 in the
Phoenix field.
In
December 2006, we acquired a 100% working interest in the Camelot gas field in
the North Sea in exchange for the assumption of certain decommissioning
liabilities estimated at approximately $7.6 million. In June 2007, we sold
a 50% working interest in this property for approximately $1.8 million and
the assumption by the purchaser of 50% of the decommissioning liability of
approximately $4.0 million. We recognized a gain of approximately
$1.6 million as a result of this sale. In February 2010, we
acquired our joint interest partner and as a result we own a 100% interest in
the Camelot field. We are now obligated to pay the entire abandonment
obligation for the field (estimated to range between $10-$15
million). The acquired entity had secured its field abandonment
obligations with a $10 million letter of credit which was fully collateralized
with cash.
In
2007, we incurred $25.1 million of plug and abandonment overruns related to
hurricanes Katrina
and Rita,
partially offset by insurance recoveries of $4.0 million. In addition, we
increased our abandonment liability at December 31, 2007 for work yet to be
done for certain properties damaged by the hurricanes totaling
$9.6 million, partially offset by estimated insurance recoveries of
$4.9 million.
On
September 30, 2007, we sold a 30% working interest in the Phoenix, Boris
oilfield and the Little Burn oilfield (Green Canyon Block 238) to
Sojitz GOM Deepwater, Inc. (“Sojitz”), a wholly owned subsidiary of Sojitz
Corporation, for a cash payment of $40 million and the proportionate
recovery of all past and future capital expenditures related to the
re-development of the fields, excluding the conversion of the Helix
Producer I, which we plan to use as a redeployable floating production
unit (“FPU”). Proceeds of $51.2 million from the sale were collected in
October 2007. Sojitz will also pay its
103
proportionate share
of the operating costs including fees payable for the use of the FPU. A gain of
approximately $40.4 million was recorded in 2007.
In
March and April 2008, we sold a total 30% working interest in the Bushwood
discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental
Shelf oil and gas properties (East Cameron Blocks 371 and 381), in two separate
transactions to affiliates of a private independent oil and gas company for
total cash consideration of approximately $183.4 million (which included the
purchasers’ share of incurred capital expenditures on these fields), and
additional potential cash payments of up to $20 million based upon certain field
production milestones. The new co-owners will also pay their pro rata
share of all future capital expenditures related to the exploration and
development of these fields. Decommissioning liabilities will be
shared on a pro rata share basis between the new co-owners and
us. Proceeds from the sale of these properties were used to pay down
our outstanding revolving loans in April 2008. As a result of these
sales, we recognized a pre-tax gain of $91.6 million in the first half of
2008.
In
May 2008, we sold all our interests in our onshore proved and unproved oil and
gas properties located in the states of Texas, Mississippi, Louisiana, New
Mexico and Wyoming (“Onshore Properties”) to an unrelated investor. We sold
these Onshore Properties for cash proceeds of $47.3 million and recorded a
related loss of $11.9 million in the second quarter of 2008. Proceeds
from the sale of these properties were used to reduce amounts under our
outstanding loans in May 2008. Included in the cost basis of the
Onshore Properties was an $8.1 million allocation of goodwill from our Oil and
Gas segment.
In
December 2008, we announced the sale of all our interests in the Bass Lite field
(Atwater Block 426), a 17.5% working interest, to our joint interest owners in
the field for approximately $49 million. The sale had an effective
date of November 1, 2008. Proceeds from the sale were used to fund
our working capital requirements.
In
2009, we farmed-out our 100% leasehold interests in Green Canyon Block 490
located in the deepwater of the Gulf of Mexico. Our farm out
agreement was structured such that the operator paid 100% of the drilling costs
to evaluate the prospective reservoir. The operator has drilled the well
and it was successful in finding commercial quantities of hydrocarbons. We
have elected to participate for a 25 percent working interest in setting
production casing and the right to participate in all subsequent
operations. Well completion and development options are being evaluated
for the new discovery.
Impairments
Proved property impairment charges
are reflected as reductions in cost of sales in the accompanying consolidated
statements of operations.
In
2007, we recorded impairment expense of approximately $64.1 million related
to our proved oil and gas properties primarily as a result of downward reserve
revisions and weak end of life well performance in some of our domestic
properties. In addition, we recorded approximately $9.9 million of
impairment expense related to our unproved properties primarily due to
management’s assessment that exploration activities would not commence prior to
the respective lease expiration dates. Further, we expensed approximately
$5.9 million of dry hole exploratory costs in fourth quarter of 2007
related to our South Marsh Island 123 #1 well drilled in 2007 due to
management’s decision not to execute previous development plans prior to the
lease expiring. Lastly, 2007 depletion was impacted by certain producing
properties that experienced significant proved reserve declines, thus causing a
significant increase in the depletion rate for these properties.
As
a result of our unsuccessful development well in January 2008 on Devil’s Island
(Garden Banks Block 344), we recognized impairment expense of $14.6 million in
2008 related to the cost incurred subsequent to December 31,
2007. The $20.9 million of the costs incurred related to this well
through December 31, 2007, were charged to earnings in 2007.
In
2008, impairment expense totaled approximately $215.7 million ($192.6 million
recorded in the fourth quarter of 2008) related to our proved oil and gas
properties primarily as a result of downward reserve revisions reflecting lower
oil and natural gas prices, weak end of life well performance for some of our
domestic properties, fields lost as a result of Hurricanes Gustav and Ike and the reassessment of the economics of
some of our marginal fields in light of our announced business strategy
de-emphasis portions of our the oil and gas exploration and production
business; we also recorded a $14.6 million asset impairment charge
associated with the Devil’s Island Development well (Garden Banks Block 344)
that was determined to be non-commercial in January 2008.
In
2009, we recorded impairment expense totaling $120.6 million ($55.9 million in
fourth quarter of 2009) related to reductions in our estimated proved reserves
for twelve of our oil and gas fields at December 31, 2009 primarily reflecting
mechanical and production issues at the related fields. In the
second quarter of 2009, we recorded an aggregate of approximately $63.1 million
of impairment charges. These charges primarily reflect the approximate $51.5
million of impairment-related charges recorded to properties that were severely
damaged by Hurricane Ike (Note
4). Separately, we also recorded $11.5 million of impairment charges
to reduce the asset carrying value of four fields following reductions in their
estimated proved reserves as evaluated at June 30, 2009.
Note 7 —
Details of Certain Accounts (in thousands)
Other current
assets consisted of the following as of December 31, 2009 and
2008:
|
2009
|
2008
|
||||||
|
Other receivables
|
$
|
7,990
|
$
|
22,977
|
|||
|
Prepaid insurance
|
11,105
|
18,327
|
|||||
|
Other prepaids
|
21,819
|
23,956
|
|||||
|
Spare parts inventory
|
25,755
|
32,195
|
|||||
|
Current deferred tax
assets
|
24,517
|
3,978
|
|||||
|
Hedging assets
|
6,214
|
26,800
|
|||||
|
Insurance claims to be
reimbursed
|
—
|
7,880
|
|||||
|
Income tax receivable
|
8,492
|
23,485
|
|||||
|
Gas imbalance
|
7,655
|
7,550
|
|||||
|
Other
|
7,784
|
4,941
|
|||||
|
$
|
121,331
|
$
|
172,089
|
Other assets, net,
consisted of the following as of December 31, 2009 and 2008:
|
2009
|
2008
|
|||||||
|
Restricted cash
|
$
|
35,409
|
$
|
35,402
|
||||
|
Deferred drydock costs,
net
|
12,030
|
38,620
|
||||||
|
Deferred financing costs
|
30,061
|
33,431
|
||||||
|
Intangible assets with finite
lives
|
768
|
7,600
|
||||||
|
Other
|
3,945
|
10,669
|
||||||
|
$
|
82,213
|
$
|
125,722
|
Accrued liabilities
consisted of the following as of December 31, 2009 and 2008:
|
2009
|
2008
|
|||||||
|
Accrued payroll and related
benefits
|
$
|
30,513
|
$
|
46,224
|
||||
|
Royalties payable
|
5,717
|
10,265
|
||||||
|
Current decommissioning
liability
|
65,729
|
31,116
|
||||||
|
Unearned revenue
|
3,672
|
9,353
|
||||||
|
Billings in excess of
costs
|
—
|
13,256
|
||||||
|
Insurance claims to be
reimbursed
|
—
|
7,880
|
||||||
|
Accrued interest
|
27,830
|
34,299
|
||||||
|
Deposits
|
25,542
|
25,542
|
||||||
|
Hedging liability
|
19,536
|
7,687
|
||||||
|
Other
|
21,617
|
46,057
|
||||||
|
$
|
200,156
|
$
|
231,679
|
Note 8 —
Equity Investments
In
June 2002, we formed Deepwater Gateway with Enterprise Products Partners, L.P.,
in which we each own a 50% interest, to design, construct, install, own and
operate a tension leg platform (“TLP”) production hub in deepwater of the Gulf
of Mexico. Deepwater Gateway primarily services the Marco Polo field, which is
owned and operated by Anadarko Petroleum Corporation. Our share of the Deepwater
Gateway construction costs was approximately $120 million and our
investment totaled $103.3 million and $106.3 million as of
December 31, 2009 and 2008, respectively, and was included in our
Production Facilities segment. The investment balance at December 31, 2009
and 2008 included approximately $1.5 million and $1.6 million,
respectively, of capitalized interest and insurance paid by us.
In
December 2004, we acquired a 20% interest in Independence Hub, an affiliate of
Enterprise. Independence Hub owns the Independence Hub platform located in
Mississippi Canyon Block 920 in a water depth of 8,000 feet. The
platform reached mechanical completion in May 2007. First production
began in July 2007. Our investment in Independence Hub was $86.1 million
and $90.2 million as of December 31, 2009 and 2008, respectively
(including capitalized interest of $5.6 million and $5.9 million at
December 31, 2009 and 2008, respectively), and was included in our
Production Facilities segment.
During 2007, CDI determined that
there was an other than temporary impairment of its equity investment in OTSL
and the full value of its investment was impaired. CDI recorded
equity losses in OTSL of $10.8 million, inclusive of the impairment charge, and
$0.5 million for the fiscal years ended December 31, 2007, and 2006,
respectively. CDI sold its equity interest in OTSL to a third party in January
2009 for $0.4 million.
We made the
following contributions to our equity investments during the years ended
December 31, 2009, 2008 and 2007 (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Independence Hub
|
$
|
—
|
$
|
—
|
$
|
12,475
|
||||||
|
Other
|
1,657
|
846
|
4,984
|
|||||||||
|
Total
|
$
|
1,657
|
$
|
846
|
$
|
17,459
|
||||||
We received the
following distributions from our equity investments during the years ended
December 31, 2009, 2008 and 2007 (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Deepwater
Gateway
|
$
|
6,750
|
$
|
23,500
|
$
|
27,000
|
||||||
|
Independence Hub
|
26,000
|
25,000
|
10,800
|
|||||||||
|
Total
|
$
|
32,750
|
$
|
48,500
|
$
|
37,800
|
||||||
Note 9 —
Kommandor LLC
In
October 2006, we partnered with Kommandor RØMØ, a Danish corporation,
to form Kommandor LLC, a Delaware limited liability company, the purpose of
which was to convert a ferry vessel into a ship-shaped dynamically-positioned
floating production unit vessel. Upon completion of the conversion in April
2009, the vessel, (the Helix
Producer I) was leased to us under a bareboat charter. We are
performing additional capital modifications in order to utilize the vessel for
future use as a floating production system servicing the Deepwater Gulf of
Mexico, with initial service being provided for the Phoenix field, in
which we hold an approximate 70% working interest. The initial investment for
our 50% interest in Kommandor LLC was $15 million. We provided $98.9
million in interim construction financing to the joint venture and Kommandor
provided a $5.0 million loan. During 2009, $58.8 million of this
amount was converted to equity in our investment in Kommandor LLC. At December
31, 2009, Kommandor had $25.7 million of borrowings outstanding to us and $3.7
million to Kommandor RØMØ. These amounts were used to fund the
conversion of the vessel. The vessel’s conversion is to
be completed in two phases. The first phase, the initial conversion,
was completed in April 2009 at a total cost of approximately $170 million. We
then charted the vessel from Kommandor LLC, and transported it from Greece to
the Gulf of Mexico where it commenced installation of production facilities
upgrades. The second phase is
106
expected to be
completed by mid year 2010. Estimated costs for the capital
modifications to the vessel in the second phase, in which we expect to fund
100%, will range between $190 and $200 million.
The operating
agreement with Kommandor RØMØ, provides that for a period of two months
immediately following the fifth anniversary of the completion of the initial
conversion (April 2014 – June 2014), we may purchase Kommandor RØMØ’s 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 LLC at the time the put
or call is exercised to be approximately $28 million.
The
consolidated results of Kommandor LLC are included in our Production Facilities
segment. We own approximately 81% of Kommandor LLC at December 31,
2009. Kommandor LLC was a development stage enterprise since
its inception in October 2006 to April 2009.
Note 10 —
Long-Term Debt
Senior
Unsecured Notes
On
December 21, 2007, we issued $550 million of 9.5% Senior
Unsecured Notes due 2016 (“Senior Unsecured Notes”). The Senior Unsecured Notes
are fully and unconditionally guaranteed by substantially all of our existing
restricted domestic subsidiaries, except Cal Dive I-Title XI, Inc. In
addition, any future guarantee of our or any of our restricted subsidiaries’
indebtedness is also required to guarantee the Senior Unsecured Notes. CDI, the
subsidiaries of CDI, and our foreign subsidiaries are not guarantors of the
Senior Unsecured Notes. We used the proceeds from the Senior Unsecured Notes to
repay outstanding indebtedness under our Senior Secured Credit Facilities (see
below).
The Senior
Unsecured Notes are junior in right of payment to all our existing and future
secured indebtedness and obligations and rank equally in right of payment with
all existing and future senior unsecured indebtedness of the Company. The Senior
Unsecured Notes rank senior in right of payment to any of our future
subordinated indebtedness and are fully and unconditionally guaranteed by the
guarantors listed above on a senior basis.
The Senior
Unsecured Notes mature on January 15, 2016. Interest on the Senior
Unsecured Notes accrues at the fixed rate of 9.5% per annum and is payable
semiannually in arrears on each January 15 and July 15, commencing
July 15, 2008. Interest is computed on the basis of a 360-day year
comprising twelve 30-day months.
Included in the
Senior Unsecured Notes indenture are terms, conditions and covenants that are
customary for this type of offering. The covenants include limitations on our
and our subsidiaries’ ability to incur additional indebtedness, pay dividends,
repurchase our common stock, and sell or transfer assets. As of
December 31, 2009, we were in compliance with these covenants.
The Senior
Unsecured Notes may be redeemed prior to the stated maturity under the following
circumstances:
|
•
|
After
January 15, 2012, we may redeem all or a portion of the Senior
Unsecured Notes, on not less than 30 days’ nor more than 60 days’
prior notice, at the redemption prices (expressed as percentages of the
principal amount) set forth below, plus accrued and unpaid interest, if
any, thereon, to the applicable redemption
date.
|
|
Year
|
Redemption
Price
|
|
|
2012
|
104.750%
|
|
|
2013
|
102.375%
|
|
|
2014 and thereafter
|
100.000%
|
|
•
|
In addition,
at any time prior to January 15, 2011, we may use the net proceeds
from any equity offering to redeem up to an aggregate of 35% of the
total principal amount of Senior Unsecured Notes at a
redemption price equal to 109.5% of the cumulative principal amount of the
Senior Unsecured Notes redeemed, plus accrued and unpaid interest, if any,
to the redemption date, provided that this redemption provision shall not
be applicable with respect to any transaction that results in a change of
control of the Company. At least 65% of the aggregate principal
amount of Senior Unsecured Notes must remain outstanding immediately after
the occurrence of such redemption.
|
In
the event a change of control of the Company occurs, each holder of the Senior
Unsecured Notes will have the right to require us to purchase all or any part of
such holder’s Senior Unsecured Notes. In such event, we are required to offer to
purchase all of the Senior Unsecured Notes at a purchase price in cash in an
amount equal to 101% of the principal amount, plus accrued and unpaid interest,
if any, to the date of purchase.
Senior
Credit Facilities
In
July 2006, we entered into a credit agreement (the “Senior Credit Facilities”)
under which we borrowed $835 million in a term loan (the “Term Loan”) and
were initially able to borrow up to $300 million (the “Revolving Loans”) under a
revolving credit facility (the “Revolving Credit Facility”). The proceeds
from the Term Loan were used to fund the cash portion of the Remington Oil and
Gas Corporation acquisition. Total borrowing capacity under the
Revolving Credit Facility at December 31, 2009 totaled $435 million. The
full amount of the Revolving Credit Facility may be used for issuances of
letters of credit. At December 31, 2009 we had no amounts drawn on
the Revolving Credit Facility and our availability under the Facility totaled
$385.8 million net of $49.2 million of unsecured letters of credit
issued.
The Term Loan bears
interest either at the one-, three- or six-month LIBOR at our current election
plus a 2.00% margin (as amended in February 2010, the margin has been increased
up to 2.50% depending on current leverage ratios, as defined) . Our
average interest rate on the Term Loan for the years
December 31, 2009 and 2008 was approximately 4.2% and 6.0%, respectively
(including the effects of our interest rate swaps). The Revolving
Loans bear interest based on one-, three- or six-month LIBOR rates or on Base
Rates at our current election plus an applicable margin as discussed
below. Margins on the Revolving Loans will fluctuate in relation to
the consolidated leverage ratio as provided in the Credit
Agreement. The average interest rate on the Revolving Loans was
approximately 3.4% through date of their repayment in the second quarter of
2009. We have no amounts outstanding under the revolver at
December 31, 2009.
In
February 2010, we amended the Senior Credit Facility. This
amendment:
|
·
|
amends the
consolidated leverage ratio that we are required to comply with. Through
December 31, 2009, maximum permitted leverage was 3.50 to 1.00. Beginning
with the quarter ending March 31, 2010, the ratio will be changed as
follows:
|
|
o
|
March 31,
2010 – 5.00 to 1.00
|
|
o
|
June 30, 2010
– 5.50 to 1.00
|
|
o
|
September 30,
2010 – 5.00 to 1.00
|
|
o
|
December 31,
2010 – 4.50 to 1.00
|
|
o
|
March 31,
2011 and thereafter – 4.00 to 1.00
|
|
·
|
adds a new
Senior Credit Facility leverage ratio we are required to comply with
beginning with the quarter ending March 31, 2010. The ratio will be as
follows:
|
|
o
|
March 31 and
June 30, 2010 – 2.50 to 1.00
|
|
o
|
September 30,
2010 – 2.25 to 1.00
|
|
o
|
December 31,
2010 and thereafter – 2.00 to 1.00
|
|
·
|
increases the
margin on Revolving Loans by 0.50% should the consolidated leverage
ratio equal or exceed 4.50 to 1.00 and increases the margin on the
Term Loan by 0.25% if consolidated leverage ratio is less than 4.50 to
1.00 and 0.50% if the consolidated leverage ratio is equal to or greater
than 4.50 to 1.00.
|
In October 2009, we
amended our Senior Credit Facility. Among other things, the
amendment:
|
·
|
extends the
maturity of the revolving line of credit under the Credit Agreement from
July 1, 2011 to November 30, 2012;
|
|
·
|
permits the
disposition of certain oil and gas properties without a limit as to value,
provided that we use 60% of the proceeds from such sales to make certain
mandatory prepayments of the Term Loan (40% of the proceeds can be
reinvested into collateral);
|
|
·
|
relaxes
limitations on our right to dispose of the Caesar
vessel, by permitting the disposition of the Caesar
provided that we use 60% of the proceeds from such sale to make certain
mandatory prepayments of the Term Loan and permits us to contribute the
Caesar
to a joint venture or similar arrangement (40% of the proceeds can
be reinvested into collateral);
|
|
·
|
increases the
maximum amount of all investments permitted in subsidiaries that are
neither loan parties nor whose equity interests are pledged from $100
million to $150 million;
|
|
·
|
increases the
amount of restricted payments in the form of stock repurchases or
redemptions such that we are permitted to repurchase or redeem up to $50
million of our common stock in the event we prepay an aggregate
amount on the term loan greater than $200 million (up to $25 million if we
prepay at least $100 million);
|
|
·
|
amends the
applicable margins under the revolving lines of credit under the Credit
Agreement (ranging from 3.0% to 4.0% on LIBOR loans and 2.0% to 3.0% on
Base Rate loans); and
|
|
·
|
increases the accordion
feature that allows Helix to increase the revolving line of credit by $100
million (to $550 million) at any time in future periods with lender
approval.
|
We
also completed an increase in the revolving line of credit from
$420 million to $435 million (decreasing to $410 million beginning
July 1, 2011 through November 30, 2012) utilizing the accordion feature included
in the Credit Agreement through an increase in the commitments from existing and
new lenders.
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. 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 remaining excess will then be
applied to the Revolving Loans.
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 Company’s 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 certain minimum financial ratios for interest coverage, consolidated
leverage, senior secured debt leverage and, until we achieve investment grade
ratings from S&P and Moody’s, 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, 2009, we were in compliance with all debt
covenants.
The Loans and our
other obligations to the Lenders under the Loan Documents are guaranteed by all
of our U.S. subsidiaries except Cal Dive I-Title XI, Inc., and
are secured by a lien on substantially all of our assets and properties and all
the assets and properties of our U.S. subsidiaries except Cal Dive
I-Title XI, Inc. 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 certain 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.
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, and qualified for hedge accounting. On December 21,
2007, a prepayment made to a hedged portion of our Term Loan brought the balance
of that portion below the amount hedged by interest rate swaps. As a result, the
hedge instruments became ineffective and no longer
109
qualify for hedge
accounting as of that date. The final contracts settled in the fourth
quarter of 2009. In January 2010, we entered into $200
million, two-year interest rate swaps to stabilize cash flows
relating to a portion of our interest payments on our Term
Loan.
Convertible
Senior Notes
In
March 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 in December 2005, the initial conversion rate of the
Convertible Senior Notes of 15.56 shares of common stock per $1,000 principal
amount of the Convertible Senior Notes, 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, including a change of control (as
defined) or the termination of trading of our common stock on a listed exchange.
The effective interest rate for the Convertible Senior Notes was 6.6% following
the adoption of ASC Topic No. 470-20 “Debt
with Conversion and Other Options” (Note 2).
The Convertible
Senior Notes can be converted prior to the stated maturity under the following
circumstances:
|
•
|
during any
fiscal quarter 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. At December 31, 2009, the
conversion trigger was not met.
Our weighted
average share price for 2009 was below the conversion price of $32.14 per share.
The maximum number of shares of common stock which may be issued upon conversion
of the Convertible Senior Notes is 13,303,770. We registered the
13,303,770 shares of common stock that may be issued upon conversion of the
Convertible Senior Notes as well as 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.
MARAD
Debt
At
December 31, 2009 and 2008, $119.2 million and $123.4 million,
respectively, was outstanding on our long-term financing used for construction
of the Q4000
(“MARAD Debt”).
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. 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 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. At December 31, 2009, we are in compliance
with these debt covenants.
Other
We
paid financing costs associated with our debt totaling $7.1 million in 2009 and
$2.2 million in 2008. Deferred financing costs of $30.1 million and
$33.4 million at December 31, 2009 and 2008, respectively, are included
within the caption “Other Assets, Net” in the accompanying consolidated balance
sheets and are being amortized over the life of the respective agreements. In
December 2007, as a result of prepaying $400 million of borrowing under our
Term Loan, we charged $3.5 million to interest expense representing the
proportionate share of the deferred financing cost related to the prepaid amount
of the Term Loan.
Scheduled
maturities of long-term debt and capital lease obligations outstanding as of
December 31, 2009 were as follows (in thousands):
|
Helix
Term Loan
|
Helix
Revolving Loans
|
Senior
Unsecured Notes
|
Convertible Senior Notes(1)
|
MARAD
Debt
|
Loan Note(2)
|
Total
|
|||||||||||||||||
|
Less than one year
|
$
|
4,326
|
$
|
─
|
$
|
─
|
$
|
─
|
$
|
4,424
|
$
|
3,674
|
$
|
12,424
|
|||||||||
|
One to two years
|
4,326
|
─
|
─
|
─
|
4,645
|
—
|
8,971
|
||||||||||||||||
|
Two to three years
|
4,326
|
─
|
─
|
─
|
4,877
|
—
|
9,203
|
||||||||||||||||
|
Three to four years
|
401,788
|
─
|
─
|
─
|
5,120
|
—
|
406,908
|
||||||||||||||||
|
Four to five years
|
─
|
─
|
─
|
─
|
5,376
|
—
|
5,376
|
||||||||||||||||
|
Over five years
|
─
|
─
|
550,000
|
300,000
|
94,793
|
—
|
944,793
|
||||||||||||||||
|
Total debt
|
414,766
|
─
|
550,000
|
300,000
|
119,235
|
3,674
|
1,387,675
|
||||||||||||||||
|
Current maturities
|
(4,326
|
)
|
─
|
─
|
─
|
(4,424
|
)
|
(3,674
|
)
|
(12,424
|
)
|
||||||||||||
|
Long-term
debt, less
current
maturities
|
410,440
|
─
|
550,000
|
300,000
|
114,811
|
—
|
1,375,251
|
||||||||||||||||
|
Unamortized
debt
Discount
(3)
|
─
|
─
|
─
|
(26,936
|
)
|
—
|
—
|
(26,936
|
)
|
||||||||||||||
|
Long-term debt
|
$
|
410,440
|
$
|
─
|
$
|
550,000
|
$
|
273,064
|
$
|
114,811
|
$
|
—
|
$
|
1,348,315
|
|||||||||
|
(1)
|
Beginning in
December 2012, we may at our option repurchase notes or the holders may
require repurchase of notes.
|
|
(2)
|
Represents
the balance of loan provided by Kommandor RØMØ to Kommandor LLC as of
December 31, 2009.
|
|
(3)
|
Reflects debt discount
resulting from adoption of new provisions of ASC Topic No. 470-20 “Convertible
Debt and Other Options” on January 1, 2009. The
notes will increase to $300 million face amount through accretion of
non-cash interest charges through
2012.
|
We
had unsecured letters of credit outstanding at December 31, 2009 totaling
approximately $49.2 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, 2009, 2008 and 2007 (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Interest expense
|
$
|
105,775
|
$
|
136,989
|
$
|
107,752
|
||||||
|
Interest income
|
(923
|
)
|
(2,416
|
)
|
(9,231
|
)
|
||||||
|
Capitalized interest
|
(48,119
|
)
|
(42,125
|
)
|
(31,790
|
)
|
||||||
|
Interest
expense, net
|
$
|
56,733
|
$
|
92,448
|
$
|
66,731
|
||||||
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 were required to accrue
income tax expense on our share of CDI’s net income after the initial public
offering in all periods where we consolidated their operations. The
deconsolidation of CDI’s net income after its initial public offering did not
have a material impact on our consolidated results of operations; however,
because of our inability to recover our tax basis in CDI tax free, a long term
deferred tax liability was provided for any incremental tax increases to the
book over tax basis.
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 U.S. statutory rate of 35% and at the
local statutory rate for each foreign jurisdiction adjusted for items which are
allowed as deductions for federal and foreign 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,
|
||||||||
|
2009
|
2008
|
2007
|
||||||
|
Statutory rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
||
|
Foreign provision
|
(1.1
|
)
|
2.6
|
(1.4
|
)
|
|||
|
IRC Section 199 deduction
|
(1.2
|
)
|
0.7
|
(0.2
|
)
|
|||
|
CDI equity pick up in excess
of tax basis
|
3.0
|
(4.2
|
)
|
─
|
||||
|
Nondeductible
goodwill impairment (Note 2)
|
─
|
(50.0
|
)
|
─
|
||||
|
Other
|
0.9
|
(1.7
|
)
|
(0.1
|
)
|
|||
|
Effective
rate
|
36.6
|
%
|
(17.6
|
)%
|
33.3
|
%
|
||
Components of the
provision (benefit) for income taxes reflected in the statements of operations
consisted of the following (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Current
|
$
|
160,829
|
$
|
92,181
|
$
|
46,780
|
||||||
|
Deferred
|
(65,007
|
)
|
(5,402
|
)
|
125,082
|
|||||||
|
$
|
95,822
|
$
|
86,779
|
$
|
171,862
|
|||||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Domestic
|
$
|
94,388
|
$
|
42,780
|
$
|
147,219
|
||||||
|
Foreign
|
1,434
|
43,999
|
24,643
|
|||||||||
|
$
|
95,822
|
$
|
86,779
|
$
|
171,862
|
|||||||
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, 2009 and
2008 were as follows (in thousands):
|
2009
|
2008
|
||||||
|
Deferred tax
liabilities:
|
|||||||
|
Depreciation
and depletion
|
$
|
432,567
|
$
|
638,363
|
|||
|
Subsidiary
book basis in excess of tax
|
834
|
71,048
|
|||||
|
Equity
investments in production facilities
|
54,122
|
41,839
|
|||||
|
Prepaid and
other
|
48,312
|
57,230
|
|||||
|
Total
deferred tax liabilities
|
$
|
535,835
|
$
|
808,480
|
|||
|
Deferred tax
assets:
|
|||||||
|
Net
operating loss carryforward
|
$
|
(4,415
|
) |
$
|
(3,533
|
)
|
|
|
Decommissioning
liabilities
|
(84,572
|
) |
(150,337
|
)
|
|||
|
Reserves,
accrued liabilities and other
|
(28,758
|
) |
(46,401
|
)
|
|||
|
Total
deferred tax assets
|
$
|
(117,745
|
) |
$
|
(200,271
|
)
|
|
|
Valuation
allowance
|
─
|
3,317
|
|||||
|
Net
deferred tax liability
|
$
|
418,090
|
$
|
611,526
|
|||
|
Deferred
income tax is presented as:
|
|||||||
|
Current deferred
tax asset
|
$
|
(24,517
|
) |
$
|
(3,978
|
)
|
|
|
Noncurrent
deferred tax liabilities
|
442,607
|
615,504
|
|||||
|
Net
deferred tax liability
|
$
|
418,090
|
$
|
611,526
|
We
consider the undistributed earnings of our principal non-U.S. subsidiaries
to be permanently reinvested. At December 31, 2009 and 2008, our principal
non-U.S. subsidiaries had accumulated earnings and profits of approximately
$58.0 million and $51.2 million, respectively. We have not provided
deferred U.S. income tax on the accumulated earnings and profits.
Alternatively, as a result of our inability to recover our tax basis in CDI tax
free, we have provided a deferred tax liability on the incremental increases to
the book over tax basis.
We have adopted the
uncertain tax position provisions of ASC Topic No. 740 “Income
Taxes.” We account for tax related interest in interest expense and tax
penalties in operating expenses. During 2009, we recorded a $0.8
million long term liability for uncertain tax benefits, interest and
penalty. At December 31, 2009, 2008, and 2007 there are $3.4 million,
$5.2 million and $0.6 million of unrecognized tax benefits that if recognized
would affect the annual effective rate. A reconciliation of the
beginning and ending amount of unrecognized tax benefits is as follows (in
thousands):
|
2009
|
2008
|
2007
|
||||||||||
|
Balance at
January
1,
|
$
|
5,183
|
$
|
640
|
$
|
─
|
||||||
|
Additions
based on tax positions related to current year
|
─
|
2,643
|
─
|
|||||||||
|
Additions for
tax positions of prior
years
|
773
|
1,900
|
640
|
|||||||||
|
Reductions
for tax positions of prior
years
|
(2,539
|
)
|
─
|
─
|
||||||||
|
Balance at
December
31,
|
$
|
3,417
|
$
|
5,183
|
$
|
640
|
We
file tax returns in the U.S. and in various state, local and
non-U.S. jurisdictions. We anticipate that any potential adjustments to our
state, local and non-U.S. jurisdiction tax returns by tax authorities would
not have a material impact on our financial position. The tax periods ending
December 31, 2006, 2007, 2008 and 2009 remain subject to examination by the
U.S. Internal Revenue Service (“IRS”). In addition, as we acquired
Remington on July 1, 2006 we are exposed to any tax uncertainties related
to Remington. For Remington, the tax period ending June 30, 2006 remains
subject to examination by the IRS. In non-U.S. jurisdictions, the open tax
periods primarily include 2007, 2008 and 2009.
In December 2006,
we entered into the Tax Matters Agreement with CDI in connection with the CDI
initial public offering. For the year ended December 31,
2009, this agreement did not have a material impact on our consolidated results
of operations.
Note 12 —
Convertible Preferred Stock
In
January 2003, we completed the private preferred 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) convertible
into 1,666,668 shares of our common stock at $15 per share. The
preferred stock was issued to a private investment firm, Fletcher International,
Ltd. (“Fletcher”). Subsequently on June 2004, Fletcher exercised an
existing right to purchase an additional $30 million of cumulative convertible
preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value
$0.01 per share) convertible into 1,964,058 shares of our common stock at $15.27
per share. Pursuant to the agreement governing the preferred stock
(the “Fletcher Agreement”), Fletcher was entitled to convert the preferred
shares into common stock at any time, and to redeem the preferred shares into
common stock at any time after December 31, 2004. In January 2009,
Fletcher issued a redemption notice with respect to all its shares of the Series
A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we
issued and delivered 5,938,776 shares of our common stock to Fletcher based on a
redemption price of $5.05 per share as determined by the average closing price
of our common stock on the three days starting on the third day prior to holder
redeeming the shares of Series A-2 Cumulative Preferred
Stock. Accordingly, in the first quarter of 2009 we recognized a
$29.3 million charge to reflect the terms of this redemption, which was recorded
as a reduction to our net income applicable to common
shareholders. This beneficial conversion charge reflected the value
associated with the additional 3,974,718 shares delivered over the original
1,964,058 shares that were contractually required to be issued upon conversion
but was limited to the $29.3 million of net proceeds we received from the
issuance of the Series A-2 Cumulative Convertible Preferred Stock.
The Fletcher
Agreement provides that if the volume weighted average price of our common stock
on any date is less than a certain minimum price (calculated at $2.767
subsequent to the above described redemption), then our right to pay Fletcher
dividends in our common stock is extinguished, and we are required to deliver a
notice to Fletcher that either (1) the conversion price will be reset to such
minimum price (in which case Fletcher shall have no further right to cause the
redemption of the preferred stock), or (2) in the event Fletcher exercises its
redemption rights, we will satisfy our redemption obligations either in cash, or
a combination of cash and common stock subject to a maximum number of shares
(14,973,814) that can be delivered to Fletcher under the Fletcher
Agreement. On February 25, 2009, the volume weighted average price of our
common stock was below the minimum price, and on February 27, 2009 we provided
notice to Fletcher that with respect to the Series A-1 Cumulative Convertible
Preferred Stock the conversion price is reset to $2.767 as of that date and that
Fletcher shall have no further rights to redeem the shares, and we have no
further right to pay dividends in common stock. Subsequent to this election, the
conversion price is not subject to any further adjustment or
reset. As a result of the reset of the conversion price, Fletcher was
entitled to receive an aggregate of 9,035,056 shares in future conversion(s)
into our common stock based on the fixed $2.767 conversion price. In the event
we elect to settle any future conversion in cash, Fletcher would receive cash in
an amount approximately equal to the value of the shares it would receive upon a
conversion, which could be substantially greater than the original face amount
of the Series A-1 Cumulative Convertible Preferred Stock, and which would result
in additional beneficial conversion charges in our statement of operations.
Under the existing terms of our Senior Credit Facilities we are not permitted to
deliver cash to the holder upon a conversion of the Convertible Preferred
Stock.
In
connection with the reset of the conversion price of the Series A-1 Cumulative
Convertible Preferred Stock to $2.767, we were required to recognize a $24.1
million charge to reflect the value associated with the additional 7,368,388
shares that will be required to be delivered upon any future conversion(s) over
the 1,666,668 shares that were to be delivered under the original contractual
terms. This $24.1 million charge was recorded as a beneficial
conversion charge reducing our net income applicable to common
shareholders. Similar to the beneficial conversion charge associated
with the redemption of Series A-2 Cumulative Convertible Preferred Stock, the
beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred
Stock is limited to the $24.1 million of net proceeds received upon its
issuance.
On
July 23, 2009 and August 12, 2009, Fletcher provided a notice of conversion
informing us of its election to convert 15,000 shares and 4,000 shares,
respectively, of the Series A-1 Cumulative Convertible Preferred Stock into
5,421,033 shares and 1,445,608 shares, respectively, of our common
stock. In connection with the closing of each these conversions we also
paid the accrued and unpaid dividends associated with these shares in cash, the
amount of which was immaterial at the time of the conversion
notice. The conversions were consummated on July 27, 2009 and
August 14, 2009, respectively.
At
December 31, 2009, we had 6,000 shares of convertible preferred stock
outstanding, which are convertible into 2,168,413 shares of our common stock,
which represents the maximum number of shares that can be issued to Fletcher in
future conversion transactions. The convertible preferred stock
maintains its mezzanine presentation below liabilities but is not included as
component of shareholders’ equity, because we may, under certain instances, be
required to settle any future conversions in
cash.
The common shares
issuable in connection with this convertible preferred stock outstanding are
included in our diluted earnings per share computations using the “if converted”
method based on the applicable conversion price of $2.767 per share, meaning
that for almost all future reporting periods in which we have positive earnings
and our average stock price exceeds $2.767 per share we will have an assumed
conversion of convertible preferred stock and the applicable number of our
shares (2,168,413 shares at December 31, 2009) will be included in our diluted
shares outstanding amount.
The preferred stock
has a minimum annual dividend rate of 4%, subject to adjustment, payable
quarterly in cash. The
dividend rate was 4% in 2009 and 2008 and 6.4% in 2007. At the time
these dividends were paid we had the option to pay them in our common stock; we
paid them in cash.
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 employee’s contribution up to 5 percent
of the employee’s salary. Our costs related to deferred compensation plans
totaled $1.5 million, $3.0 million and $2.8 million for the years ended
December 31, 2009, 2008 and 2007, respectively. These
amounts include $2.1 million and $1.4 million associated with CDI deferred
compensation plans in 2008 and 2007, 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”),
which expired at end of 2008. As of December 31, 2009, there were
approximately 1.7 million shares available for grant under our 2005 Incentive
Plan.
Upon adoption
of the 1995 Incentive Plan in May 1995, a maximum of 10% of the total
shares of common stock issued and outstanding were eligible to 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 in
May 2005, no further grants have been or will be made under the 1995 Incentive
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
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 former ESPP plan 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, restricted stock, restricted
stock units, and cash awards. Awards granted to employees under the 1995 and
2005 Incentive Plans typically vest 20% per year over 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.
We
account for our stock-based compensation plans under ASC Topic No. 718 “Compensation
– Stock Compensation”. 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 as
historical forfeitures have been immaterial. Forfeitures on restricted stock
totaled approximately 14% based on our historical forfeitures
rate. 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. We did not grant any stock
options in 2009, 2008 or 2007.
Stock
Options
The options
outstanding at December 31, 2009, have exercise prices as follows:
139,000 shares at $8.57; 82,774 shares at $10.92; 30,400 shares at
$10.94; 30,000 shares at $11.00; 127,680 shares at $12.18;
52,800 shares at $13.91; and 38,664 shares ranging from $8.14 to
$10.59, and a weighted average remaining contractual life of
3.1 years.
Options outstanding
are as follows:
|
2009
|
2008
|
2007
|
||||||||||||||||||||||
|
Shares
|
Weighted
Average Exercise Price
|
Shares
|
Weighted
Average Exercise Price
|
Shares
|
Weighted
Average Exercise Price
|
|||||||||||||||||||
|
Options
outstanding at beginning of year
|
521,654
|
$10.66
|
736,550
|
$10.55
|
883,070
|
$10.86
|
||||||||||||||||||
|
Exercised
|
(20,336
|
)
|
$ 8.67
|
(214,896
|
)
|
$10.28
|
(141,186
|
)
|
$11.10
|
|||||||||||||||
|
Terminated
|
—
|
—
|
—
|
—
|
(5,334
|
)
|
$10.92
|
|||||||||||||||||
|
Options outstanding at end of
year
|
501,318
|
$10.74
|
521,654
|
$10.66
|
736,550
|
$10.55
|
||||||||||||||||||
|
Options exercisable end of
year
|
501,318
|
$10.74
|
473,054
|
$10.44
|
537,514
|
$10.28
|
||||||||||||||||||
For the years ended
December 31, 2009, 2008 and 2007, $0.1 million, $1.1 million (of which
$0.6 million of compensation expense was recognized in the first half of 2008
related to the acceleration of unvested options per the separation agreements
between the Company and two of our former executive officers) and
$1.0 million, respectively, was recognized as compensation expense related
to stock options. The aggregate intrinsic value of the stock options exercised
in 2009, 2008 and 2007 was approximately $0.1 million, $5.9 million and
$4.1 million, respectively. The aggregate intrinsic value of options
exercisable at December 31, 2009 was approximately $0.5 million. There was
no aggregate intrinsic value of options exercisable at December 31, 2008 as the
fair market value at year end was lower than the exercise price of the vested
stock options. The aggregate intrinsic value of options exercisable at December
31, 2007 was $16.8 million.
Restricted
Shares
We
grant restricted shares to members of our board of directors, all executive
officers and selected management employees. Compensation cost for each award is
the product of grant date 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, 2009, 2008 and 2007:
|
2009
|
2008
|
2007
|
|||||||||||||||||||
|
Shares
|
Grant Date Fair Value(1)
|
Shares
|
Grant Date Fair Value(1)
|
Shares
|
Grant Date Fair Value(1)
|
||||||||||||||||
|
Restricted
shares outstanding at beginning of year
|
1,206,526
|
$32.84
|
1,166,077
|
$32.19
|
729,212
|
$ 32.29
|
|||||||||||||||
|
Granted
|
656,887
|
7.12
|
702,190
|
$34.01
|
702,297
|
$ 31.77
|
|||||||||||||||
|
Vested
|
(327,777
|
)
|
33.69
|
(386,963
|
)
|
$31.19
|
(236,667
|
)
|
$ 31.32
|
||||||||||||
|
Forfeited
|
(92,371
|
)
|
8.90
|
(274,778
|
)
|
$35.40
|
(28,765
|
)
|
$ 31.59
|
||||||||||||
|
Restricted
shares outstanding at end of year
|
1,443,265
|
22.47
|
1,206,526
|
$32.84
|
1,166,077
|
$ 32.19
|
|||||||||||||||
|
(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 years ended
December 31, 2009, 2008 and 2007, $9.4 million, $18.5 million (of which
$3.6 million was related to the accelerated vesting of restricted shares per the
separation agreements between the Company and two of our former executive
officers during the first half of 2008) and $11.7 million, respectively,
was recognized as compensation expense related to restricted shares. In 2008 and
2007, compensation expense of $4.8 and $2.1 million, respectively, was
related to the CDI Incentive Plan. Future compensation cost associated with
unvested restricted stock awards at December 31, 2009 and 2008 totaled
approximately $21.8 million and $53.3 million, respectively, of which
$23.4 million related to the CDI Incentive Plan at December 31, 2008. The
weighted average vesting period related to nonvested restricted stock awards at
December 31, 2009 was approximately 3.2 years.
In January 2010, we
granted executive officers and select management employees 452,849 and 23,569
restricted shares and restricted stock units, respectively, under the 2005
Long-Term Incentive Plan. The shares and units vest 20% per year for a five-year
period. The market value of the restricted stock is based on the quoted market
price of the common stock on the business day prior to the grant date. The
market value of the restricted shares was $11.75 per share or $5.6 million.
We also granted certain of our outside directors 1,197 restricted shares. The
shares vest on January 1, 2012. The market value of the restricted shares
was $11.75 per share or $14,065.
Employee
Stock Purchase Plan
In
May 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% 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 the lesser of 10% of
an employee’s base salary or $25,000 of our stock value. Shares
of our common stock issued to our employees under the ESPP totaled 98,933 shares
in 2008 and 222,984 in 2007. In 2007, we subsequently repurchased
approximately the same number of shares of our common stock in the open market
at a weighted average price of $35.04 per share and reduced the number of shares
of our outstanding common stock. Under this plan 97,598 shares of common stock
were purchased in the open market for our employees at a weighted-average share
price of $33.12 during 2006. For the years ended December 31, 2008 and
2007, we recognized $1.8 million and $2.1, respectively, of compensation expense
related to stock purchased under the ESPP and the CDI ESPP (of which $1.2
million and $0.6 million of expense for the years ended December 31, 2008 and
2007, respectively, was related to the CDI ESPP that became effective in the
third quarter of 2007).
In
January 2009, we issued 25,393 shares of our common stock to our employees
under this plan to satisfy the employee purchase period from July 1, 2008
to December 31, 2008, which increased our common stock
outstanding. There are no longer any shares available under this
plan.
Stock
Compensation Modifications
Under our 1995
Incentive Plan and our 2005 Long-Term Incentive Plan, upon a stock recipient’s
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 fell to 50% or below (the “Trigger
Date”), the options and unvested shares granted to CDI employees would have been
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 CDI 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). 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.
Long-Term
Incentive Cash Plan
In January
2009, we adopted the 2009 Long-Term Incentive Cash Plan (the “2009 LTI Plan”) to
provide certain long-term cash based compensation to eligible
employees. Under terms of the 2009 LTI Plan, the majority
of the cash awards, which vest over a five-year period of
employment, are made in a fixed sum amount. Our Executive
Officers and certain other members of senior management are granted cash awards.
The amount of the payment on each applicable payment anniversary
date will fluctuate based upon the Company’s stock
performance. The share-based cash awards are measured
based on the performance of our stock price over the
applicable award period compared to a base price determined by the Compensation
Committee of the Board of Directors at the time of the
award. The measurement period to determine the annual payment
for the share-based cash awards is the last 20 trading days of the year
(modified from the last 30 trading days as applied to the 2009
awards). Payment amounts are based on the calculated ratio of the
average stock price during the annual measurement period over the original base
price. The maximum amount payable under these share-based cash
awards is twice the original targeted award and if the average price
during the measurement period is less than 50% of the base price, no payout will
be made at the applicable anniversary date. Payments under
the 2009 LTI Plan are made each year on
the anniversary date of the award. The
share-based component of our 2009 LTI
117
Plan is considered
a liability plan under the guidance of ACS Topic No. 718 “Compensation
– Stock Compensation” and as such will be re-measured to fair value each
reporting period with corresponding changes be recorded as a charge to income as
appropriate.
The total awards
made under the 2009 LTI Plan totaled $14.7 million in 2009, including $8.1
million for our Executive Officers. For the year ended December
31, 2009, $3.7 million ($2.6 million related to Executive Officers) was
recognized as compensation expense related to the 2009 LTI Plan and paid in
January 2010. In January 2010, $10.1 million was awarded under the
2009 LTI Plan to eligible employees, including $6.0 million to our Executive
Officers and other members of senior management.
Note 14 —
Shareholders’ Equity
Our amended and
restated Articles of Incorporation provide for authorized Common Stock of
240,000,000 shares with no stated par value per share and
5,000,000 shares of preferred stock, $0.01 par value per share
issuable in one or more series.
The components of
accumulated other comprehensive income (loss) as of December 31, 2009 and
2008 were as follows (in thousands):
|
2009
|
2008
|
|||||||
|
Cumulative
foreign currency translation adjustment
|
$
|
(12,257
|
)
|
$
|
(42,874
|
)
|
||
|
Unrealized gain (loss) on
hedges, net
|
(9,097
|
)
|
9,178
|
|||||
|
Unrealized loss on investment
available for sale
|
(887
|
)
|
─
|
|||||
|
Accumulated
other comprehensive loss
|
$
|
(22,241
|
)
|
$
|
(33,696
|
)
|
Note 15 —
Stock Buyback Program
In
June 2009, we announced that we intend to purchase up to 1.5 million shares plus
an amount equal to additional shares granted under the stock-based compensation
plans (Note 13) of our common stock as permitted under our Senior Credit
Facility. Our Board of Directors had previously granted us the
authority to repurchase shares of our common stock in an amount equal to any
equity grants made pursuant to our stock-based compensation plans. We
may continue to make repurchases pursuant to this authority from time to time as
additional equity grants are made under our stock based compensation plans based
upon prevailing market conditions and other factors. All repurchases
may be commenced or suspended at any time at the discretion of
management. As of December 31, 2009, we had repurchased a total of
1,048,431 shares of our common stock for $13.4 million or an average of $12.80
per share. We retired all shares repurchased.
Note 16 —
Related Party Transactions
Cal
Dive International, Inc.
Subsequent to the
initial public offering of Cal Dive from time to time, we have
provided 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 $0.9
million for the period of January 1, 2009 through deconsolidation in June
2009. Total allocated services to Cal Dive totaled
approximately $4.0 million and $3.6 million for the years ended
December 31 2008 and 2007, respectively.
Included in these
costs are costs related to the participation by CDI’s employees in our employee
benefit plans through December 31, 2007, 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
$9.2 million for the year ended December 31, 2007. Our defined
contribution 401(k) retirement plan is further disclosed in Note
13.
In
addition, through December 31, 2007, 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
$3.4 million for the year ended December 31, 2007. These amounts are
eliminated in the accompanying consolidated financial statements.
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 CDI’s business, allocates liabilities (including
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 to the other. In addition, the Master
Agreement provides us with a preferential right to use a specified number of
CDI’s vessels in accordance with the terms of such agreement.
Pursuant to the
Corporate Services Agreement, each party agreed to provide specified services to
the other party, including administrative and support services for the time
period specified therein. Generally once we ceased 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 were 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 as originally entered into by
the parties we provided CDI with services related to the tax, treasury, audit,
insurance (including claims) and information technology functions; CDI provided
us with services related to the human resources, training and orientation
functions, and certain supply chain and environmental, health and safety
services. However, the Corporate Services Agreement was amended effective
January 1, 2008 and effective January 1, 2009 to reflect that CDI no longer
provides us with these functions, and to reflect that we only provide CDI with
certain information technology and insurance services. This Agreement was
terminated in August 2009 upon mutual agreement between Cal Dive and
us.
Pursuant to the
Employee Matters Agreement, except as otherwise provided, CDI generally accepted
and assumed 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 stock. Those employees were 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 permitted CDI employees to participate in our Employee Stock
Purchase Plan for the offering period that ended June 30, 2007, and CDI
paid us $1.6 million in July 2007, which was 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 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. 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 Helix’s 20%
working interest. Production from the Gunnison field commenced in
December 2003. We have made payments to OKCD totaling $11.3 million,
$21.6 million and $22.1 million in the years ended December 31,
2009, 2008 and 2007 respectively. Our Chief Executive Officer, Owen
Kratz, through Class A limited partnership interests in OKCD, personally
owns approximately 80.4% of the partnership. Martin Ferron, our former President
and Chief Executive Officer, owns approximately 1.2% of the partnership and A.
Wade Pursell, our former Executive Vice President and Chief Financial Officer,
owns approximately 0.4% of the partnership. In 2000, OKCD also
awarded Class B limited partnership interests to key Helix
employees.
During 2009, 2008
and 2007, we paid $3.3 million,$3.4 million and $12.3 million,
respectively, to Weatherford International, Ltd. (“Weatherford”), an oil and gas
industry company, for services provided to us. A member of our board
of directors is part of the senior management team of Weatherford.
In
2009, we made $0.2 million in rental payments to Mine Maintenance Management
whose partners include two current employees of our wholly owned WOSEA
subsidiary. We currently lease from Mine Maintenance an
office building and a fabrication facility both located in Perth,
Australia.
Note 17 —
Commitments and Contingencies
Lease
Commitments
We lease several
facilities, ROVs and vessels under noncancelable operating leases. Future
minimum rentals under these leases are approximately $99.1 million at
December 31, 2009 with $43.8 million due in 2010, $36.3 million
in 2011, $15.3 million in 2012, $1.6 million in 2013,
$1.3 million in 2014 and $0.8 million thereafter. Total rental expense
under these operating leases was approximately $89.9 million, $59.6 million
and $76.0 million for the years ended December 31, 2009, 2008 and
2007, respectively.
Insurance
We
carry Hull and Increased Value insurance which provides coverage for physical
damage up 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,
Helix Producer I and Well
Enhancer,$500,000 on the Intrepid,
Seawell and Express and $375,000 on the Caesar.
In addition to the primary deductibles the vessels are subject to an
Annual Aggregate Deductible of $1.25 million. We also carry
Protection and Indemnity (“P&I”) insurance which covers liabilities arising
from the operation of the vessels and General Liability insurance which covers
liabilities arising from construction operations. The deductible on both the
P&I and General Liability is $100,000 per occurrence. Onshore employees are
covered by Workers’ Compensation. Offshore employees, 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 deductible. In addition
to the liability policies named above, we currently carry various layers of
Umbrella Liability for total limits of $500 million excess of primary limits.
Our self-insured retention on our medical and health benefits program for
employees is $250,000 per participant.
We
incur workers’ compensation and other insurance claims in the normal course of
business, which management believes are covered by insurance. The Company
analyzes each claim for potential exposure and estimates the ultimate liability
of each claim. At December 31, 2009 we did not have any claims exceeding our
deductible limits. At December 31, 2008, our liability above the
applicable deductible limits was $7.9 million and we had a corresponding
$7.9 million receivable from the insurance companies. These amounts are
reflected in Accrued Liabilities and Other Current Assets in the consolidated
balance sheet (Note 7). 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
On
December 2, 2005, we received an order from the U.S. Department of the
Interior Minerals Management Service (“MMS”) that the price threshold for both
oil and gas was exceeded for 2004 production and that royalties were due on such
production notwithstanding the provisions of the Outer Continental Shelf Deep
Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate
exploration and production of oil and natural gas in the deepwater Gulf of
Mexico by providing relief from the obligation to pay royalty on certain federal
leases up to certain specified production volumes. Our oil and gas leases
affected by this dispute are Garden Banks Blocks 667, 668 and 669
(“Gunnison”). On May 2, 2006, the MMS issued another order that superseded
the December 2005 order, and claimed that royalties on gas production are due
for 2003 in addition to oil and gas production in 2004. The order also seeks
interest on all royalties allegedly due. We filed a timely notice of appeal with
respect to both the December 2005 Order and the May 2006 Order.
120
We received an
additional order from the MMS dated September 30, 2008 stating that the price
thresholds for oil and gas were exceeded for 2005, 2006 and 2007 production and
that royalties and interest are payable, as well as an additional order from the
MMS dated August 28, 2009 stating the price thresholds for oil and natural gas
were exceeded for 2008 and that royalties and interest are payable. We appealed
these orders on the same basis as the previous orders.
Other operators in
the Deep Water Gulf of Mexico who have received notices similar to ours sought
royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison.
In March of 2006, Kerr-McGee filed a lawsuit in federal district court
challenging the enforceability of price thresholds in certain deepwater Gulf of
Mexico leases, including ours. On October 30, 2007, the federal district
court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held
that the Department of the Interior exceeded its authority by including the
price thresholds in the subject leases. The
government appealed the district court’s decision. On
January 12, 2009, the United States Court of Appeals for the Fifth Circuit
affirmed the decision of the district court in favor of Kerr-McGee, holding that
the DWRRA unambiguously provides that royalty suspensions up to certain
production volumes established by Congress apply to leases that qualify under
the DWRRA. After the appellate court denied a request by the
plaintiff for rehearing, the plaintiff subsequently petitioned the United States
Supreme Court for a writ of certiorari for the Supreme Court to review the Fifth
Circuit Court’s decision. In October 2009, the United States Supreme
Court announced its decision to deny the plaintiff’s writ of certiorari,
concluding the litigation in this dispute.
As
a result of this dispute, we had been recording reserves for the disputed
royalties (and any other royalties that may be claimed for production during
2005, 2006, 2007 and 2008) plus interest at 5% for our portion of the
Gunnison related MMS claim. The result of accruing these reserves
since 2005 had reduced our oil and gas revenues. Following the
decision of the United States Court of Appeals for the Fifth Circuit Court, we
reversed our previously accrued royalties ($73.5 million) to oil and gas
revenues in the first quarter of 2009. Effective in January 2009, we
commenced recognizing oil and natural gas sales revenue associated with this
disputed net revenue interest and are no longer accruing any additional royalty
reserves as we believed it was remote that we would be liable for such amounts
in future. This belief was confirmed with the United States Supreme
Court decision to deny the plaintiff’s writ of certiorari in October
2009.
Contingencies
A
number of our longer term pipelay contracts have been adversely affected by
delays in the delivery of the
Caesar. We believe two of our contracts qualify as loss
contracts as defined under SOP 81-1 “Accounting
for Performance of Construction-Type and Certain Production-Type
Contracts." Accordingly, we have estimated the future
shortfall between our anticipated future revenues versus future
costs. For one contract that was completed in May 2009, our loss was
$0.8 million, all of which was provided with our estimated loss accrual at
December 31, 2008. Under a second contract, which was terminated, we
had a potential future liability of up to $25 million. As of December
31, 2008, we estimated the loss under this contract at $9.0
million. In the second quarter of 2009, services under this contract
were substantially completed and we revised our estimated loss to approximately
$15.8 million. To reflect this additional estimated loss we recorded
an additional $6.8 million charge to cost of sales in the accompanying condensed
consolidated statement of operations. We recently agreed to
settle our obligation under this contract for $12.7
million. Accordingly we reversed $3.1 million of our previously
accrued costs under this contract to reduce it from the estimated $15.8 million
loss to $12.7 million at December 31, 2009. We have paid
$7.2 million of the $12.7 million of estimated damages related to this
terminated contract and expect to pay the remaining $5.5 million in the second
quarter of 2010.
In March
2009, we were notified of a third party’s intention to terminate an
international construction contract based on a claimed breach of that contract
by one of our subsidiaries. As there are substantial defenses to this
claimed breach, we cannot at this time determine if we have
any exposure under the contract. In 2010, we will
continue to assess our potential exposure to damages under this contract as the
circumstances warrant. Under the terms of the contract, our potential
liability is generally capped for actual damages at approximately $27
million Australian dollars (“AUD”) (approximately $24.3 million US dollars at
December 31, 2009) and for liquidated damages at approximately $5
million AUD (approximately $4.5 million US dollars at December 31, 2009).
At December 31, 2009, we have a $4.0 million AUD (approximately $3.6 million US
dollars at December 31, 2009) receivable against our counterparty for work
performed prior to the termination of the contract. We continue to
pursue payment for this work as well as other claims against our
counterparty. We have asserted a counterclaim that in the aggregate
approximates $12 million U.S. dollars.
Commitments
We
are converting the Caesar
(acquired in January 2006 for $27.5 million in cash) into a
deepwater pipelay vessel. Total conversion costs are estimated to range between
$290 million and $300 million (including capitalized interest of
approximately $24 million), of which approximately $264.8 million had been
incurred, with an additional $2.3 million committed, at December 31,
2009. We expect the Caesar
to join our fleet in the first half of 2010.
Further, we, along
with Kommandor Rømø, a Danish corporation, formed a joint venture company called
Kommandor LLC and converted a ferry vessel into a floating production unit to be
named the Helix
Producer I.
The total cost of the ferry and the conversion was approximately $170 million.
We provided $98.9 million in interim construction financing to the joint
venture. During 2009, $58.8 million of this amount was converted to
equity in our investment in Kommandor LLC. Kommandor Rømø provided a
$5.0 million loan to Kommandor LLC, the remaining balance of which was $3.7
million at December 31, 2009.
Total equity
contributions and indebtedness guarantees provided by Kommandor Rømø are
expected to total $42.5 million. The remaining costs to complete the
project will be provided by Helix through equity contributions. Under
the terms of the operating agreement of the joint venture, Kommandor Rømø
elected not to make further contributions to the joint venture, thus the
ownership interests in the joint venture were adjusted based on the relative
contributions of each partner (including guarantees of indebtedness) to the
total of all contributions and project financing guarantees.
Upon completion of
the initial conversion, which occurred in April 2009, we chartered the Helix
Producer I from Kommandor LLC., and are installing, at 100% our cost,
processing facilities and a disconnectable fluid transfer system on the Helix
Producer I for use on our Phoenix field. The cost of these additional
facilities is estimated to range between $190 million and $200 million
(including capitalized interest of $16 million) and the work is expected to be
completed in the first half of 2010. As of December 31, 2009,
approximately $269 million of costs related to the purchase of the Helix
Producer I ($20 million), conversion of the Helix
Producer I and construction of the additional facilities had been
incurred, with an additional $12.1 million committed. The total
estimated cost of the vessel, initial conversion and the additional facilities
will range approximately between $360 million and $370 million. We
have consolidated Kommandor LLC in all periods presented in the accompanying
consolidated financial statements. The results of Kommandor LLC are
included within our Production Facilities segment.
As
of December 31, 2009, we planned to spend approximately $16 million for
additional capital improvements to newly constructed Well
Enhancer vessel and have committed to spend $58.7 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 business: contracting services operations and oil and gas
operations. We have disaggregated our contracting services operations into three
reportable segments in accordance with ASC Topic No 280 “Segment
Reporting”: Contracting Services, Shelf Contracting and Production
Facilities. As a result, our reportable segments consisted of the following:
Contracting Services, Shelf Contracting, Oil and Gas and Production Facilities.
Contracting Services operations include deepwater pipelay, well operations,
robotics and drilling. Shelf Contracting operations consisted of CDI, which
included all assets deployed primarily for diving-related activities and shallow
water construction. On June 10, 2009, we ceased consolidating CDI when our
remaining ownership interest decreased to below 50% following the sale of a
portion of CDI common stock held by us (Note 3). We continued to
disclose the results of Shelf Contracting business as a segment up to and
through June 10, 2009. 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) is accounted for under the equity method of accounting. We
consolidate our investment in Kommandor LLC and its results are included within
our Production Facilities segment.
The following
summarizes certain financial data by business segment:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues
─
|
||||||||||||
|
Contracting
Services
|
$
|
796,158
|
$
|
961,926
|
$
|
673,808
|
||||||
|
Shelf
Contracting
|
404,709
|
856,906
|
623,615
|
|||||||||
|
Oil
and
Gas
|
385,338
|
545,853
|
584,563
|
|||||||||
|
Production
Facilities(2)
|
17,248
|
—
|
—
|
|||||||||
|
Intercompany
elimination
|
(141,766
|
)
|
(250,611
|
)
|
(149,566
|
)
|
||||||
|
Total
|
$
|
1,461,687
|
$
|
2,114,074
|
$
|
1,732,420
|
||||||
|
Income (loss)
from operations ─
|
||||||||||||
|
Contracting
Services
|
$
|
118,176
|
$
|
181,983
|
$
|
160,866
|
||||||
|
Shelf
Contracting(1)
|
59,077
|
179,711
|
183,130
|
|||||||||
|
Oil
and
Gas
|
91,668
|
(709,966
|
)
|
123,353
|
||||||||
|
Production
Facilities(2)
|
(3,918
|
)
|
(719
|
)
|
(847
|
)
|
||||||
|
Corporate
|
(47,734
|
)
|
(39,220
|
)
|
(32,215
|
)
|
||||||
|
Intercompany
elimination
|
(13,454
|
)
|
(26,011
|
)
|
(23,008
|
)
|
||||||
|
Total(4)
|
$
|
203,815
|
$
|
(414,222
|
)
|
$
|
411,279
|
|||||
|
Net interest
expense and other ─
|
||||||||||||
|
Contracting
Services
|
$
|
(2,280
|
)
|
$
|
12,454
|
$
|
4,707
|
|||||
|
Shelf
Contracting
|
6,642
|
22,285
|
9,259
|
|||||||||
|
Oil
and
Gas
|
20,152
|
47,599
|
49,580
|
|||||||||
|
Production
Facilities
|
2,011
|
386
|
331
|
|||||||||
|
Corporate
and
eliminations
|
24,970
|
28,374
|
3,170
|
|||||||||
|
Total
|
$
|
51,495
|
$
|
111,098
|
$
|
67,047
|
||||||
|
Equity in
losses of OTSL, inclusive of impairment
|
$
|
—
|
$
|
—
|
$
|
(10,841
|
)
|
|||||
|
Equity in
earnings of equity investments excluding OTSL
|
$
|
32,329
|
$
|
31,854
|
$
|
30,414
|
||||||
|
Income (loss)
before income taxes ─
|
||||||||||||
|
Contracting
Services(3)
|
$
|
120,456
|
$
|
169,529
|
$
|
156,159
|
||||||
|
Shelf
Contracting(1)
|
52,435
|
157,426
|
163,030
|
|||||||||
|
Oil
and
Gas
|
71,516
|
(757,565
|
)
|
73,773
|
||||||||
|
Production
Facilities(2)
|
18,300
|
30,749
|
29,236
|
|||||||||
|
Corporate
and
eliminations
|
(715
|
)
|
(93,605
|
)
|
93,303
|
|||||||
|
Total
|
$
|
261,992
|
$
|
(493,466
|
)
|
$
|
515,501
|
|||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Provision
(benefit) for income taxes ─
|
||||||||||||
|
Contracting
Services
|
$
|
43,334
|
$
|
56,018
|
$
|
51,091
|
||||||
|
Shelf
Contracting
|
16,275
|
47,927
|
57,430
|
|||||||||
|
Oil
and
Gas
|
23,352
|
(15,092
|
)
|
24,896
|
||||||||
|
Production
Facilities
|
6,198
|
12,569
|
10,509
|
|||||||||
|
Corporate
and
eliminations
|
6,663
|
(14,643
|
)
|
27,936
|
||||||||
|
Total
|
$
|
95,822
|
$
|
86,779
|
$
|
171,862
|
||||||
|
Identifiable
assets ─
|
||||||||||||
|
Contracting
Services
|
$
|
1,738,005
|
$
|
1,572,618
|
$
|
1,135,981
|
||||||
|
Shelf
Contracting
|
—
|
1,309,608
|
1,274,050
|
|||||||||
|
Oil
and
Gas
|
1,541,153
|
1,708,428
|
2,634,238
|
|||||||||
|
Production
Facilities
|
499,497
|
457,197
|
366,634
|
|||||||||
|
Discontinued
operations
|
878
|
19,215
|
38,612
|
|||||||||
|
Total
|
$
|
3,779,533
|
$
|
5,067,066
|
$
|
5,449,515
|
||||||
|
Capital
expenditures ─
|
||||||||||||
|
Contracting
Services
|
$
|
204,228
|
$
|
258,184
|
$
|
286,362
|
||||||
|
Shelf
Contracting
|
39,569
|
83,108
|
30,301
|
|||||||||
|
Oil
and
Gas
|
137,168
|
404,308
|
519,632
|
|||||||||
|
Production
Facilities
|
44,065
|
110,300
|
123,545
|
|||||||||
|
Discontinued
operations
|
—
|
476
|
1,215
|
|||||||||
|
Total
|
$
|
425,030
|
$
|
856,376
|
$
|
961,055
|
||||||
|
Depreciation
and amortization ─
|
||||||||||||
|
Contracting
Services
|
$
|
53,411
|
$
|
44,489
|
$
|
37,588
|
||||||
|
Shelf
Contracting(1)
|
34,243
|
71,195
|
40,698
|
|||||||||
|
Oil
and
Gas
|
168,101
|
215,605
|
250,371
|
|||||||||
|
Production
Facilities
|
3,295
|
—
|
—
|
|||||||||
|
Corporate
and
eliminations
|
3,567
|
|
2,437
|
1,141
|
||||||||
|
Total
|
$
|
262,617
|
$
|
333,726
|
$
|
329,798
|
||||||
|
(1)
|
Includes
$(10.8) million equity in (losses) earnings from CDI’s investment in
OTSL in 2007.
|
|
(2)
|
In April
2009, Kommandor LLC commenced leasing the Helix
Producer I to us under terms of a charter
arrangement following the completion of the initial conversion
of the vessel (Note 9). We are currently completing some
capital upgrades to the vessel which are expected to be completed by mid
year 2010. At that time the vessel will be used in our
Phoenix field.
|
|
(3)
|
Includes
pre-tax gain of $151.7 million related to CDI’s Horizon acquisition
in 2007 and 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 in 2006.
|
|
(4)
|
Includes
$704.3 million of goodwill impairment charges for year ending December 31,
2008 associated with our oil and gas segment. Also
includes approximately $120.6 million, $215.7 million and $64.1
million of asset impairment charges for certain oil and gas properties for
the years ended December 31, 2009, 2008 and 2007
respectively.
|
Intercompany
segment revenues during the years ended December 31, 2009, 2008 and 2007
were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Contracting Services
|
$
|
120,048
|
$
|
195,207
|
$
|
115,864
|
||||||
|
Shelf Contracting
|
7,865
|
55,404
|
33,702
|
|||||||||
|
Production Facilities
|
13,853
|
—
|
—
|
|||||||||
|
Total
|
$
|
141,766
|
$
|
250,611
|
$
|
149,566
|
||||||
Intercompany
segment profit (which only relates to intercompany capital projects) during the
years ended December 31, 2009, 2008 and 2007 were as follows (in
thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Contracting Services
|
$
|
13,205
|
$
|
20,945
|
$
|
10,026
|
||||||
|
Shelf Contracting
|
365
|
5,066
|
12,982
|
|||||||||
|
Production Facilities
|
(116
|
)
|
—
|
—
|
||||||||
|
Total
|
$
|
13,454
|
$
|
26,011
|
$
|
23,008
|
||||||
Revenue by
geographic region during the years ended December 31, 2009, 2008 and 2007
were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
United States
|
$
|
923,481
|
$
|
1,394,108
|
$
|
1,261,844
|
||||||
|
United Kingdom
|
124,896
|
160,186
|
205,529
|
|||||||||
|
India
|
233,466
|
214,288
|
36,433
|
|||||||||
|
Other
|
179,844
|
|
345,492
|
228,614
|
||||||||
|
Total
|
$
|
1,461,687
|
$
|
2,114,074
|
$
|
1,732,420
|
||||||
We
include the property and equipment, net in the geographic region in which it is
legally owned. The following table provides our property and
equipment, net of depreciation by geographic region (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
United States
|
$
|
2,564,673
|
$
|
3,170,866
|
$
|
3,014,283
|
||||||
|
United Kingdom
|
284,637
|
206,009
|
187,551
|
|||||||||
|
Other
|
14,396
|
41,568
|
41,073
|
|||||||||
|
Total
|
$
|
2,863,706
|
$
|
3,418,443
|
$
|
3,242,907
|
||||||
Note 19 —
Allowance Accounts
The following table
sets forth the activity in our valuation accounts for each of the three years in
the period ended December 31, 2009 (in thousands):
|
Allowance
for Uncollectible Accounts
|
Deferred
Tax Asset Valuation Allowance
|
|||||||
|
Balance, December 31,
2006
|
$ | 965 | $ | — | ||||
|
Additions
|
5,122 | 2,967 | ||||||
|
Deductions
|
(3,213 | ) | — | |||||
|
Balance, December 31,
2007
|
2,874 | 2,967 | ||||||
|
Additions
|
8,989 | 350 | ||||||
|
Deductions
|
(5,958 | ) | — | |||||
|
Balance, December 31,
2008
|
5,905 | 3,317 | ||||||
|
Additions
|
9,220 | — | ||||||
|
Deductions (1)
|
(9,953 | ) | (3,317 | ) | ||||
|
Balance, December 31,
2009
|
$ | 5,172 | $ | — | ||||
|
(1)
|
Amounts
include reductions of $5.9 million to the allowance for uncollectible
accounts and $3.3 million to the deferred tax valuation
allowance to reflect the deconsolidation of Cal Dive in June 2009 (Note
3).
|
See Note 2 for a
detailed discussion regarding our accounting policy on Accounts Receivable and
Allowance for Uncollectible Accounts and Note 11 for a detailed discussion of
the valuation allowance related to our deferred tax assets.
Note 20 —
Supplemental Oil and Gas Disclosures (Unaudited)
Recent
Accounting Rules Activities
In
December 2008, the SEC announced that it had approved revisions designed to
modernize the oil and gas company reserve reporting
requirements. In January 2010, the FASB issued Accounting
Standards Update 2010-03 “Oil
and Gas Reserve Estimation and Disclosures.” We adopted these
rules on December 31, 2009 in conjunction with our year end 2009 proved reserve
estimates and have implemented the newly mandated authoritative guidance issued
by the FASB on extractive activities for oil and gas reserves estimation and
disclosures (Note 2 – New Accounting Standards).
One effect of
adoption of these rules included the application of lower prices at December 31,
2009 for both oil and natural gas than what would have been used under the
previous rule (year end price). Generally, adoption of these
new regulations had little effect on our estimates of reserves at December 31,
2009; however, the rule requiring development of proved undeveloped reserves
within five years could significantly impact future estimates of our proved
reserves (see “Proved Undeveloped Reserves” below).
The following
information regarding our oil and gas producing activities is presented pursuant
to ASC Topic No. 932-235-55 “Extractive
Activities – Oil and Gas.”
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 (in thousands):
|
2009
|
2008
|
|||||||
|
Unproved oil
and gas
properties
|
$
|
61,931
|
$
|
101,892
|
||||
|
Proved oil
and gas
properties
|
2,603,789
|
2,462,959
|
||||||
|
Total
oil and gas
properties
|
2,665,720
|
2,564,851
|
||||||
|
Accumulated
depletion, depreciation and amortization
|
(1,272,797
|
)
|
(1,023,493
|
)
|
||||
|
Net
capitalized
costs
|
$
|
1,392,923
|
$
|
1,541,358
|
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
December 31, 2009 and 2008, our oil and gas operations decommissioning
liabilities were $248.1 million and $225.8 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 (in thousands):
|
United
States
|
United
Kingdom
|
Total
|
||||||||||
|
Year Ended
December 31, 2009—
|
||||||||||||
|
Property
acquisition costs:
|
||||||||||||
|
Proved
properties
|
$ | 56 | $ | — | $ | 56 | ||||||
|
Unproved
properties
|
1,829 | — | 1,829 | |||||||||
|
Total
property acquisition costs
|
1,885 | — | 1,885 | |||||||||
|
Exploration
costs
|
39,225 | — | 39,225 | |||||||||
|
Development
costs(1)
|
71,489 | — | 71,489 | |||||||||
|
Asset
retirement cost
|
66,468 | 2,644 | 69,112 | |||||||||
|
Total
costs incurred
|
$ | 179,067 | $ | 2,644 | $ | 181,711 | ||||||
|
Year Ended
December 31, 2008—
|
||||||||||||
|
Property
acquisition costs:
|
||||||||||||
|
Proved
properties
|
$ | 2 | $ | — | $ | 2 | ||||||
|
Unproved
properties
|
13,392 | — | 13,392 | |||||||||
|
Total
property acquisition costs
|
13,394 | — | 13,394 | |||||||||
|
Exploration
costs
|
7,528 | — | 7,528 | |||||||||
|
Development
costs(1)
|
421,335 | — | 421,335 | |||||||||
|
Asset
retirement cost
|
26,891 | — | 26,891 | |||||||||
|
Total
costs incurred
|
$ | 469,148 | $ | — | $ | 469,148 | ||||||
|
Year Ended
December 31, 2007—
|
||||||||||||
|
Property
acquisition costs:
|
||||||||||||
|
Proved
properties
|
$ | 4,239 | $ | — | $ | 4,239 | ||||||
|
Unproved
properties
|
16,347 | — | 16,347 | |||||||||
|
Total
property acquisition costs
|
20,586 | — | 20,586 | |||||||||
|
Exploration
costs
|
220,237 | — | 220,237 | |||||||||
|
Development
costs(1)
|
360,428 | — | 360,428 | |||||||||
|
Asset
retirement cost
|
58,082 | — | 58,082 | |||||||||
|
Total
costs incurred
|
$ | 659,333 | $ | — | $ | 659,333 | ||||||
|
(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
Amounts in
thousands:
|
United
States
|
United
Kingdom
|
Total
|
||||||||||
|
Year Ended
December 31, 2009—
|
||||||||||||
|
Revenues
|
$ | 384,375 | $ | 963 | $ | 385,338 | ||||||
|
Production
(lifting)
costs
|
117,565 | 2,271 | 119,836 | |||||||||
|
Net
hurricane reimbursement (Note
4)
|
(23,332 | ) | — | (23,332 | ) | |||||||
|
Exploration
expenses(2)
|
24,383 | — | 24,383 | |||||||||
|
Depreciation,
depletion, amortization and accretion
|
167,812 | 1,444 | 169,256 | |||||||||
|
Proved
property impairment
charges
|
73,407 | — | 73,407 | |||||||||
|
Gain
on sale of oil and gas
properties
|
(1,949 | ) | — | (1,949 | ) | |||||||
|
Gain
on oil and gas derivative
contracts
|
(89,485 | ) | — | (89,485 | ) | |||||||
|
Selling
and administrative
expenses
|
21,495 | 59 | 21,554 | |||||||||
|
Pretax
income (loss) from producing activities
|
94,479 | (2,811 | ) | 91,668 | ||||||||
|
Income
tax expense
(benefit)
|
24,280 | (1,028 | ) | 23,252 | ||||||||
|
Results
of oil and gas producing activities(1)
|
$ | 70,199 | $ | (1,783 | ) | $ | 68,416 | |||||
|
Year Ended
December 31, 2008—
|
||||||||||||
|
Revenues
|
$ | 541,983 | $ | 3,870 | $ | 545,853 | ||||||
|
Production
(lifting)
costs
|
122,106 | 2,448 | 124,554 | |||||||||
|
Net
hurricane costs (Note
4)
|
52,361 | — | 52,361 | |||||||||
|
Exploration
expenses(2)
|
32,926 | — | 32,926 | |||||||||
|
Depreciation,
depletion, amortization and accretion
|
198,144 | 959 | 199,103 | |||||||||
|
Proved
property and goodwill impairment charges
|
901,820 | — | 901,820 | |||||||||
|
Gain
on sale of oil and gas
properties
|
(73,136 | ) | (125 | ) | (73,261 | ) | ||||||
|
Gain
on oil and gas derivative
contracts
|
(21,599 | ) | — | (21,599 | ) | |||||||
|
Selling
and administrative
expenses
|
39,219 | 696 | 39,915 | |||||||||
|
Pretax
loss from producing
activities
|
(709,858 | ) | (108 | ) | (709,966 | ) | ||||||
|
Income
tax expense
(benefit)
|
(16,242 | ) | 1,150 | (15,092 | ) | |||||||
|
Results
of oil and gas producing activities(1)
|
$ | (693,616 | ) | $ | (1,258 | ) | $ | (694,874 | ) | |||
|
Year Ended
December 31, 2007—
|
||||||||||||
|
Revenues
|
$ | 581,904 | $ | 2,659 | $ | 584,563 | ||||||
|
Production
(lifting)
costs
|
118,032 | 5,102 | 123,134 | |||||||||
|
Exploration
expenses(2)
|
26,725 | — | 26,725 | |||||||||
|
Depreciation,
depletion, amortization and accretion
|
228,083 | 615 | 228,698 | |||||||||
|
Proved
property impairment
charges
|
85,145 | — | 85,145 | |||||||||
|
Gain
on sale of oil and gas
properties
|
(42,566 | ) | (1,717 | ) | (44,283 | ) | ||||||
|
Selling
and
administrative
|
40,176 | 1,615 | 41,791 | |||||||||
|
Pretax
income (loss) from producing activities
|
126,309 | (2,956 | ) | 123,353 | ||||||||
|
Income
tax expense
(benefit)
|
26,240 | (1,344 | ) | 24,896 | ||||||||
|
Results
of oil and gas producing activities(1)
|
$ | 100,069 | $ | (1,612 | ) | $ | 98,457 | |||||
|
(1)
|
Excludes net
interest expense and other.
|
|
(2)
|
See Note 6
for additional information related to the components of our exploration
costs, including impairment charges for
expiring
unproved leases.
|
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 compliance with SEC guidelines.
Our engineering reserve estimates were prepared based upon interpretation of
production performance data and sub-surface information obtained from the
drilling of existing wells. Our internal reservoir engineers and independent
petroleum engineers analyzed 100% of our significant United States oil and gas
fields on an annual basis (106 fields as of December 31, 2009). 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.
At
December 31, 2009 we engaged Huddleston & Co., Inc. (“Huddleston”), a
independent reservoir engineering firm, to prepare a report to estimate our
proved reserves at December 31, 2009. Their proved reserve estimates
are included in this Form 10-K. Huddleston performed engineering
audits of our estimates of proved reserves at December 31, 2008 and 2007. We
prepared the proved reserve estimates associated with our one property in the
United Kingdom for all periods presented in this Form 10-K.
An
“engineering audit,” as we use the term, is a process involving an independent
petroleum engineering firm’s extensive visits, collection and examination of all
geologic, geophysical, engineering, production 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 process for Huddleston to prepare their
estimates of proved oil and natural gas reserves is substantially the
same as during their audit of our internal reserves (discussed
below). The primary difference between the audit and
preparation of the reserve report is that in the culmination of the audit,
Huddleston represented in its audit report that it believed our methodologies
are consistent with the methodologies required by the SEC, Society of Petroleum
Engineers (“SPE”) and FASB while in the preparation of the 2009 reserve report
we simply publish Huddleston’s estimates of our proved oil and natural gas
reserves.
The engineering
audit of our estimated proved oil and natural gas reserves (applicable for 2008
and 2007) 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 Form 10-K for the years ended December 31, 2008
and 2007 include only quantities that we expected to recover commercially using
the then mandated year-end 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 audits in 2008 and 2007, 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 it had satisfactorily resolved its questions relating
thereto or had independently verified such information or data. Furthermore, in
instances where decline curve analysis was not adequate in determining proved
producing reserves, Huddleston evaluated our volumetric analysis, which included
the analysis of production and pressure data. Each of the PUDs analyzed by
Huddleston included volumetric analysis, which took into consideration recovery
factors relative to the geology of the location and similar reservoirs. Where
applicable, Huddleston examined data related to well spacing, including
potential drainage from offsetting producing wells in evaluating proved reserves
for un-drilled well locations.
As
previously mentioned, Huddleston prepared the proved reserve estimates for all
of our U.S oil and gas properties at December 31, 2009. Huddleston’s report on
proved reserves is included herein as Exhibit 99.1 to this Form
10-K.
In
2008, the engineering audit by Huddleston included 100% of our producing
properties together with essentially all of our non-producing and undeveloped
properties in the U.S. 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 approximately 97% of the total discounted future net revenues.
Huddleston also analyzed the methods utilized by us in the preparation of all of
the estimated reserves and revenues. Huddleston represented in its audit report
that it believes our methodologies are consistent with the methodologies
required by the SEC, Society of Petroleum Engineers (“SPE”) and FASB. There were
no limitations imposed, nor limitations encountered by us or
Huddleston.
The following table
presents our net ownership interest in proved oil reserves (MBbls):
|
United
States
|
United(2)
Kingdom
|
Total
|
||||||||||
|
Total proved reserves at
December 31, 2006(1)
|
36,337 | — | 36,337 | |||||||||
|
Revision
of previous
estimates
|
(473 | ) | 97 | (376 | ) | |||||||
|
Production
|
(3,723 | ) | — | (3,723 | ) | |||||||
|
Purchases
of reserves in
place
|
— | — | — | |||||||||
|
Sales
of reserves in
place
|
(1,858 | ) | (49 | ) | (1,907 | ) | ||||||
|
Extensions
and
discoveries
|
9,346 | — | 9,346 | |||||||||
|
Total
proved reserves at December 31, 2007
|
39,629 | 48 | 39,677 | |||||||||
|
Revision
of previous
estimates
|
(250 | ) | (47 | ) | (297 | ) | ||||||
|
Production
|
(2,751 | ) | (1 | ) | (2,752 | ) | ||||||
|
Purchases
of reserves in
place
|
— | — | — | |||||||||
|
Sales
of reserves in
place
|
(5,277 | ) | — | (5,277 | ) | |||||||
|
Extensions
and
discoveries
|
661 | — | 661 | |||||||||
|
Total
proved reserves at December 31, 2008
|
32,012 | — | 32,012 | |||||||||
|
Revision
of previous
estimates
|
232 | — | 232 | |||||||||
|
Production
|
(2,741 | ) | — | (2,741 | ) | |||||||
|
Purchases
of reserves in
place
|
— | — | — | |||||||||
|
Sales
of reserves in
place
|
(1 | ) | — | (1 | ) | |||||||
|
Extensions
and
discoveries
|
225 | — | 225 | |||||||||
|
Total
proved reserves at December 31, 2009
|
29,727 | — | 29,727 | |||||||||
|
Total
proved developed reserves as of :
|
||||||||||||
|
December
31,
2006
|
13,328 | — | 13,328 | |||||||||
|
December
31,
2007
|
14,703 | 10 | 14,713 | |||||||||
|
December
31,
2008
|
12,809 | — | 12,809 | |||||||||
|
December
31,
2009
|
14,850 | — | 14,850 | |||||||||
|
(1)
|
Proved
reserves at December 31, 2006 included approximately
17,573 MBbls acquired from the Remington
acquisition.
|
|
(2)
|
Reflects 50%
ownership in the Camelot field’s reserves in 2009, 2008
and 2007. In February 2010 we acquired the
other
50% ownership
interest in the Camelot field (Note
6).
|
The following table
presents our net ownership interest in proved gas reserves, including natural
gas liquids (MMcf):
|
United
States
|
United(2)
Kingdom
|
Total
|
||||||||||
|
Total proved reserves at
December 31, 2006(1)
|
294,389 | 23,634 | 318,023 | |||||||||
|
Revision
of previous
estimates
|
(12,209 | ) | 5,666 | (6,543 | ) | |||||||
|
Production
|
(42,163 | ) | (300 | ) | (42,463 | ) | ||||||
|
Purchases
of reserves in
place
|
160 | — | 160 | |||||||||
|
Sales
of reserves in
place
|
(2,932 | ) | (14,700 | ) | (17,632 | ) | ||||||
|
Extensions
and
discoveries
|
187,439 | — | 187,439 | |||||||||
|
Total
proved reserves at December 31, 2007
|
424,684 | 14,300 | 438,984 | |||||||||
|
Revision
of previous
estimates
|
(32,098 | ) | (1,017 | ) | (33,115 | ) | ||||||
|
Production
|
(30,490 | ) | (333 | ) | (30,823 | ) | ||||||
|
Purchases
of reserves in
place
|
— | — | — | |||||||||
|
Sales
of reserves in place (3)
|
(73,627 | ) | — | (73,627 | ) | |||||||
|
Extensions
and discoveries (4)
|
171,987 | — | 171,987 | |||||||||
|
Total
proved reserves at December 31, 2008
|
460,456 | 12,950 | 473,406 | |||||||||
|
Revision
of previous estimates (5)
|
(44,615 | ) | (755 | ) | (45,370 | ) | ||||||
|
Production
|
(27,139 | ) | (195 | ) | (27,334 | ) | ||||||
|
Purchases
of reserves in
place
|
— | — | — | |||||||||
|
Sales
of reserves in
place
|
(7,933 | ) | — | (7,933 | ) | |||||||
|
Extensions
and
discoveries
|
6,546 | — | 6,546 | |||||||||
|
Total
proved reserves at December 31, 2009
|
387,315 | 12,000 | 399,315 | |||||||||
|
Total
proved developed reserves as of :
|
||||||||||||
|
December
31,
2006
|
156,251 | — | 156,251 | |||||||||
|
December
31,
2007
|
134,047 | 1,500 | 135,547 | |||||||||
|
December
31,
2008
|
256,794 | 950 | 257,744 | |||||||||
|
December
31,
2009
|
124,763 | — | 124,763 | |||||||||
|
(1)
|
Proved
reserves at December 31, 2006 included approximately
159,338 MMcf acquired from the Remington
acquisition.
|
|
(2)
|
Reflects 50%
ownership in the Camelot field’s reserves in 2009, 2008
and 2007. In February 2010 we acquired the
other
50% ownership
interest in the Camelot field (Note 6).
|
|
(3)
|
Amounts
represent the sale of 30% of our working interest in Bushwood in March and
April 2008, the sale of our entire
portfolio of
onshore properties in May 2008 and the sale of our Bass Lite field in
December 2008 (Note 6).
|
|
(4)
|
Includes
additional discovery of proved reserves at the Bushwood field and
formation of an area of mutual interest within the
Bushwood
field area.
|
|
(5)
|
Includes a 38
Bcfe reduction of the proved reserves at Bushwood field reflecting certain
reservoir issues for our Noonan
Gas wells
subsequent to their reestablishing sustained production in January 2009
and new geologic data collected
throughout
2009.
|
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and
Gas
Reserves
The following table
reflects the standardized measure of discounted future net cash flows relating
to our interest in proved oil and gas reserves (in thousands):
|
United
States
|
United(1)
Kingdom
|
Total
|
||||||||||
|
As of
December 31, 2009—
|
||||||||||||
|
Future
cash
inflows
|
$ | 3,166,306 | $ | 60,840 | $ | 3,227,146 | ||||||
|
Future
costs:
|
||||||||||||
|
Production
|
(618,391 | ) | (19,075 | ) | (637,466 | ) | ||||||
|
Development
and
abandonment
|
(755,726 | ) | (33,807 | ) | (789,533 | ) | ||||||
|
Future
net cash flows before income taxes
|
1,792,189 | 7,958 | 1,800,147 | |||||||||
|
Future
income tax
expense
|
(417,042 | ) | (1,560 | ) | (418,602 | ) | ||||||
|
Future
net cash
flows
|
1,375,147 | 6,398 | 1,381,545 | |||||||||
|
Discount
at 10% annual
rate
|
(387,036 | ) | (3,449 | ) | (390,485 | ) | ||||||
|
Standardized
measure of discounted future
net
cash
flows
|
$ | 988,111 | $ | 2,949 | $ | 991,060 | ||||||
|
As of
December 31, 2008—
|
||||||||||||
|
Future
cash
inflows
|
$ | 4,011,788 | $ | 113,054 | $ | 4,124,842 | ||||||
|
Future
costs:
|
||||||||||||
|
Production
|
(584,165 | ) | (12,584 | ) | (596,749 | ) | ||||||
|
Development
and
abandonment
|
(784,080 | ) | (33,150 | ) | (817,230 | ) | ||||||
|
Future
net cash flows before income taxes
|
2,643,543 | 67,320 | 2,710,863 | |||||||||
|
Future
income tax
expense
|
(777,736 | ) | (53,626 | ) | (831,362 | ) | ||||||
|
Future
net cash
flows
|
1,865,807 | 13,694 | 1,879,501 | |||||||||
|
Discount
at 10% annual
rate
|
(562,354 | ) | (4,992 | ) | (567,346 | ) | ||||||
|
Standardized
measure of discounted future
net
cash
flows
|
$ | 1,303,453 | $ | 8,702 | $ | 1,312,155 | ||||||
|
As of
December 31, 2007—
|
||||||||||||
|
Future
cash
inflows
|
$ | 6,769,106 | $ | 126,700 | $ | 6,895,806 | ||||||
|
Future
costs:
|
||||||||||||
|
Production
|
(622,842 | ) | (42,350 | ) | (665,192 | ) | ||||||
|
Development
and
abandonment
|
(883,923 | ) | (46,600 | ) | (930,523 | ) | ||||||
|
Future
net cash flows before income taxes
|
5,262,341 | 37,750 | 5,300,091 | |||||||||
|
Future
income tax
expense
|
(1,617,709 | ) | (18,850 | ) | (1,636,559 | ) | ||||||
|
Future
net cash
flows
|
3,644,632 | 18,900 | 3,663,532 | |||||||||
|
Discount
at 10% annual
rate
|
(831,705 | ) | (4,313 | ) | (836,018 | ) | ||||||
|
Standardized
measure of discounted future
net
cash
flows
|
$ | 2,812,927 | $ | 14,587 | $ | 2,827,514 | ||||||
|
(1)
|
Reflects 50%
ownership in the Camelot field’s reserves in 2009, 2008
and 2007. In February 2010 we acquired the
other
50% ownership
interest in the Camelot field (Note
6).
|
Future cash inflows
are computed by applying the appropriate prices required by FASB at each
year end, adjusted for location and quality differentials on a
property-by-property basis, to year-end quantities of proved reserves, except in
those instances where fixed and determinable price changes are provided by
contractual arrangements at year-end. The discounted future cash flow estimates
do not include the effects of our derivative instruments or forward sales
agreements. See the following table for base prices used in determining the
standardized measure:
|
United
States
|
United
Kingdom
|
Total
|
||||||||||
|
Year Ended December 31, 2009—
(1)
|
||||||||||||
|
Oil
price per
Bbl
|
$ | 58.05 | $ | — | $ | 58.05 | ||||||
|
Natural
gas prices per
Mcf
|
$ | 3.72 | $ | 5.07 | $ | 3.76 | ||||||
|
Year Ended
December 31, 2008—
|
||||||||||||
|
Oil
price per
Bbl
|
$ | 42.76 | $ | — | $ | 42.76 | ||||||
|
Natural
gas prices per
Mcf
|
$ | 5.74 | $ | 8.73 | $ | 5.83 | ||||||
|
Year Ended
December 31, 2007—
|
||||||||||||
|
Oil
price per
Bbl
|
$ | 93.98 | $ | 49.69 | $ | 93.92 | ||||||
|
Natural
gas prices per
Mcf
|
$ | 7.17 | $ | 8.69 | $ | 7.22 | ||||||
|
(1)
|
Year end
price for December 31, 2009 represents the average trailing twelve month
price for both oil and natural gas as now required under the new
accounting standards. Previously proved reserve estimates were
based on the price of oil and natural gas at December 31 of a given
reporting period.
|
The future income
tax expense was computed by applying the appropriate year-end statutory rates,
with consideration of future tax rates already legislated, to the future pretax
net cash flows less the tax basis of the associated properties. Future net cash
flows are discounted at the prescribed rate of 10%. We caution that actual
future net cash flows may vary considerably from these estimates. Although our
estimates of total proved reserves, development costs and production rates were
based on the best information available, the development and production of oil
and gas reserves may not occur in the periods assumed. Actual prices realized,
costs incurred and production quantities may vary significantly from those used.
Therefore, such estimated future net cash flow computations should not be
considered to represent our estimate of the expected revenues or the current
value of existing proved reserves.
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Principal changes
in the standardized measure of discounted future net cash flows attributable to
our proved oil and gas reserves are as follows (in thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Standardized
measure, beginning of
year
|
$
|
1,312,155
|
$
|
2,827,514
|
$
|
1,360,943
|
||||||
|
Changes
during the year:
|
||||||||||||
|
Sales,
net of production
costs
|
(265,501
|
)
|
(403,089
|
)
|
(461,430
|
)
|
||||||
|
Net
change in prices and production costs
|
(245,883
|
)
|
(1,713,458
|
)
|
1,208,823
|
|||||||
|
Changes
in future development
costs
|
(16,905
|
)
|
(109,775
|
)
|
(17,689
|
)
|
||||||
|
Development
costs
incurred
|
74,133
|
403,653
|
351,964
|
|||||||||
|
Accretion
of
discount
|
161,254
|
338,582
|
261,931
|
|||||||||
|
Net
change in income
taxes
|
257,919
|
700,071
|
(665,750
|
)
|
||||||||
|
Purchases
of reserves in
place
|
—
|
—
|
(951
|
)
|
||||||||
|
Extensions
and
discoveries
|
10,457
|
335,643
|
1,285,499
|
|||||||||
|
Sales
of reserves in
place
|
(30,124
|
)
|
(566,332
|
)
|
(247,344
|
)
|
||||||
|
Net
change due to revision in quantity estimates
|
(85,450
|
)
|
(96,096
|
)
|
(80,865
|
)
|
||||||
|
Changes
in production rates (timing) and other
|
(180,995
|
)
|
(404,558
|
)
|
(167,617
|
)
|
||||||
|
Total
|
(321,095
|
)
|
(1,515,359
|
)
|
1,466,571
|
|||||||
|
Standardized
measure, end of
year
|
$
|
991,060
|
$
|
1,312,155
|
$
|
2,827,514
|
||||||
Note 21 —
Resignation of Executive Officers
Martin Ferron
resigned as our President and Chief Executive Officer effective February 4,
2008. Concurrently, Mr. Ferron resigned from our Board of Directors.
Mr. Ferron remained employed by us through February 18, 2008, after
which his employment terminated. At the time of Mr. Ferron’s resignation,
Owen Kratz, who served as Executive Chairman of Helix, resumed the role and
assumed the duties of the President and Chief Executive Officer, and was
subsequently
133
elected as
President and Chief Executive Officer of Helix. In February 2008, we
recognized approximately $5.4 million of compensation expense (inclusive of the
expenses recorded for the acceleration of unvested stock options and restricted
stock) related to the separation agreement between us and Mr.
Ferron.
Wade Pursell
resigned as our Chief Financial Officer effective June 25, 2008. Mr.
Pursell remained employed by us through July 4, 2008, after which his employment
terminated. Anthony Tripodo, who served as the chairman of our audit
committee on our Board of Directors, was elected by our Board of Directors as
the new Chief Financial Officer effective June 25, 2008, at which time he
resigned from our Board of Directors. We recognized approximately
$2.0 million of compensation expense (inclusive of the expenses recorded for the
acceleration of unvested stock options and restricted stock) related to the
separation agreement between us and Mr. Pursell.
Note 22 —
Derivative Instruments and Hedging Activities
Derivatives
designated as hedging instruments as defined in FASB Codification Topic No. 815
Derivatives and Hedging (in thousands):
|
As
of December 31, 2009
|
As
of December 31, 2008
|
|||||||||
|
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
|||||||
|
Asset
Derivatives:
|
||||||||||
|
Oil
contracts
|
Other current
assets
|
$ | — |
Other current
assets
|
$ | 7,468 | ||||
|
Natural gas
contracts
|
Other current
assets
|
5,071 |
Other current
assets
|
7,438 | ||||||
|
Foreign
exchange forwards
|
Other current
assets
|
— |
Other current
assets
|
506 | ||||||
| $ | 5,071 | $ | 15,412 | |||||||
|
As
of December 31, 2009
|
As
of December 31, 2008
|
|||||||||
|
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
|||||||
|
Liability
Derivatives:
|
||||||||||
|
Oil
contracts
|
Accrued
liabilities
|
$ | 19,477 |
Accrued
liabilities
|
$ | — | ||||
|
Natural gas
contracts
|
Accrued
liabilities
|
59 |
Accrued
liabilities
|
— | ||||||
|
Foreign
exchange forwards
|
Accrued
liabilities
|
— |
Accrued
liabilities
|
240 | ||||||
|
Interest
rate swaps
|
Accrued
liabilities
|
— |
Accrued
liabilities
|
1,378 | ||||||
|
Interest
rate swaps
|
Other
long-term liabilities
|
— |
Other
long-term liabilities
|
347 | ||||||
| $ | 19,536 | $ | 1,965 | |||||||
Derivatives that
were not designated as hedging instruments (in thousands):
|
As
of December 31, 2009
|
As
of December 31, 2008
|
|||||||||
|
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
|||||||
|
Asset
Derivatives:
|
||||||||||
|
Natural gas
contracts
|
Other current
assets
|
$ | — |
Other current
assets
|
$ | 11,388 | ||||
|
Foreign
exchange forwards
|
Other current
assets
|
1,143 |
Other current
assets
|
— | ||||||
|
Foreign
exchange forwards
|
Other assets,
net
|
931 |
Other assets,
net
|
— | ||||||
| $ | 2,074 | $ | 11,388 | |||||||
|
Liability
Derivatives:
|
||||||||||
|
Foreign
exchange forwards
|
Accrued
liabilities
|
— |
Accrued
liabilities
|
1,205 | ||||||
|
Interest
rate swaps
|
Accrued
liabilities
|
— |
Accrued
liabilities
|
6,482 | ||||||
| $ | — | $ | 7,687 | |||||||
The following
tables present the impact that derivative instruments designated as cash flow
hedges had on our consolidated statement of operations for the years ended
December 31, 2009, 2008 and 2007 (in thousands):
|
Gain
(Loss) Recognized in OCI on Derivatives
(Effective
Portion)
|
||||||||||||
|
2009 (1)
|
2008
|
2007
|
||||||||||
|
Oil and
natural gas commodity contracts
|
$
|
(19,092
|
)
|
$
|
14,977
|
|
$
|
(8,670
|
) | |||
|
Foreign exchange forwards
|
(538
|
)
|
(72
|
)
|
1,110 | |||||||
|
Interest rate swaps
|
712
|
|
1,911
|
(2,093 | ) | |||||||
|
$
|
(18,918
|
)
|
$
|
16,816
|
|
$
|
(9,653 |
)
|
||||
|
(1)
|
All
unrealized gains (losses) related to our derivatives are expected to be
reclassified into earnings by no later than December 31,
2010.
|
|
Location
of Gain (Loss) Reclassified from Accumulated OCI into
Income
|
Gain
(Loss) Reclassified from Accumulated OCI into Income
|
||||||||||||
|
Years
Ended December 31,
|
|||||||||||||
|
2009
|
2008
|
2007
|
|||||||||||
|
Oil and natural gas
commodity contracts
|
Gain on oil
and gas derivative contracts
|
$
|
16,972
|
$
|
(23,423
|
)
|
$
|
462
|
|||||
|
Foreign exchange forwards
|
Net interest
expense and other
|
—
|
—
|
—
|
|||||||||
|
Interest rate swaps
|
Net interest
expense and other
|
(1,096
|
)
|
(1,674
|
)
|
—
|
|
||||||
|
$
|
15,876
|
$
|
(25,097
|
) |
$
|
462 | |||||||
The following
tables present the impact that derivative instruments not designated as hedges
had on our consolidated statement of operations for the years ended
December 31, 2009, 2008 and 2007 (in thousands):
|
Location
of Gain (Loss) Recognized in Income on Derivatives
|
Gain
(Loss) Recognized in Income on Derivatives
|
|||||||||||||
|
Years
Ended December 31,
|
||||||||||||||
|
2009
|
2008
|
2007
|
||||||||||||
|
Natural gas contracts
|
Gain on oil
and gas derivative contracts
|
$
|
89,485
|
$
|
21,599
|
$
|
—
|
|||||||
|
Foreign exchange
forwards
|
Net interest
expense and other
|
3,279
|
(1,115
|
)
|
—
|
|||||||||
|
Interest rate swaps
|
Net interest
expense and other
|
(468
|
)
|
(5,285
|
)
|
(618
|
)
|
|||||||
|
$
|
92,296
|
$
|
15,199
|
$
|
(618 | ) | ||||||||
Note 23 —
Quarterly Financial Information (Unaudited)
The offshore marine
construction industry in the Gulf of Mexico is highly seasonal as a result of
weather conditions and the timing of capital expenditures by oil and gas
companies. Historically, a substantial portion of our services has been
performed during the summer and fall months. As a result, historically a
disproportionate portion of our revenues and net income is earned during such
period. The following is a summary of consolidated quarterly financial
information for 2009 and 2008 (in thousands, except per share
data):
|
Quarter
Ended
|
||||||||||||||||
|
March
31,
|
June
30,
|
September
30,
|
December 31, (1)
|
|||||||||||||
|
2009
|
||||||||||||||||
|
Net revenues
|
$
|
570,975
|
$
|
494,639
|
$
|
216,025
|
$
|
180,048
|
||||||||
|
Gross profit (loss)
|
161,210
|
135,756
|
2,617
|
(56,421
|
)
|
|||||||||||
|
Net income (loss)
|
107,202
|
100,469
|
4,020
|
(55,637
|
)
|
|||||||||||
|
Net income
(loss) applicable to common shareholders
|
53,450
|
100,219
|
3,895
|
(55,697
|
)
|
|||||||||||
|
Basic earnings (loss) per
common share
|
0.55
|
1.02
|
0.04
|
(0.53
|
)
|
|||||||||||
|
Diluted earnings (loss) per
common share
|
0.50
|
0.94
|
0.04
|
(0.53
|
)
|
|||||||||||
|
Quarter
Ended
|
||||||||||||||||
|
March
31,
|
June
30,
|
September
30,
|
December 31 ,(2)
|
|||||||||||||
|
2008
|
||||||||||||||||
|
Net revenues
|
$
|
441,769
|
$
|
530,130
|
$
|
607,736
|
$
|
534,439
|
||||||||
|
Gross profit (loss)
|
118,583
|
189,078
|
199,080
|
(134,550
|
)
|
|||||||||||
|
Net income (loss)
|
73,965
|
90,531
|
60,178
|
(860,604
|
)
|
|||||||||||
|
Net income
(loss) applicable to common shareholders
|
73,084
|
89,651
|
59,297
|
(861,154
|
)
|
|||||||||||
|
Basic earnings (loss) per
common share
|
0.80
|
0.98
|
0.65
|
(9.48
|
)
|
|||||||||||
|
Diluted earnings (loss) per
common share
|
0.77
|
0.93
|
0.63
|
(9.48
|
)
|
|||||||||||
|
(1)
|
Includes
$55.9 million of impairment charges to reduce certain oil and gas
properties to their estimated fair value at December 31, 2009 and an
additional $20.1 million of impairment charges recorded to exploration
expense related to offshore leases that will expire in 2010 without
exploration capital being deployed, which is was not anticipated for these
affected leases.
|
|
(2)
|
Includes
$907.6 million of impairment charges to reduce goodwill and other
indefinite-lived intangible assets ($715 million) and certain oil and gas
properties ($192.6 million) to their estimated fair value in fourth
quarter of 2008.
|
Note 24 —
Condensed Consolidated Guarantor and Non-Guarantor Financial Information
The payment of
obligations under the Senior Unsecured Notes is guaranteed by all of our
restricted domestic subsidiaries (“Subsidiary Guarantors”) except for Cal Dive
I-Title XI, Inc. Cal Dive and its subsidiaries were never guarantors
of our Senior Unsecured Notes. Each of these Subsidiary Guarantors is
included in our consolidated financial statements and has fully and
unconditionally guaranteed the Senior Unsecured Notes on a joint and several
basis. As a result of these guarantee arrangements, we are required
to present the following condensed consolidating financial
information. The accompanying guarantor financial information is
presented on the equity method of accounting for all periods
presented. Under this method, investments in subsidiaries are
recorded at cost and adjusted for our share in the subsidiaries’ cumulative
results of operations, capital contributions and distributions and other changes
in equity. Elimination entries relate primarily to the elimination of
investments in subsidiaries and associated intercompany balances and
transactions.
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING BALANCE SHEETS
(in
thousands)
|
As
of December 31, 2009
|
|||||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||||
|
ASSETS
|
|||||||||||||||||
|
Current
assets:
|
|||||||||||||||||
|
Cash
and cash equivalents
|
$
|
258,742
|
$
|
2,522
|
$
|
9,409
|
$
|
—
|
$
|
270,673
|
|||||||
|
Accounts
receivable, net
|
49,813
|
77,399
|
18,307
|
—
|
145,519
|
||||||||||||
|
Unbilled
revenue
|
9,425
|
480
|
17,254
|
—
|
27,159
|
||||||||||||
|
Income
taxes receivable
|
38,333
|
—
|
13,795
|
(43,636
|
)
|
8,492
|
|||||||||||
|
Other
current assets
|
54,144
|
68,910
|
15,453
|
(25,668
|
)
|
112,839
|
|||||||||||
|
Current
assets of discontinued operations
|
—
|
—
|
878
|
—
|
878
|
||||||||||||
|
Total
current assets
|
410,457
|
149,311
|
75,096
|
(69,304
|
)
|
565,560
|
|||||||||||
|
Intercompany
|
106,408
|
149,796
|
(190,729
|
)
|
(65,475
|
)
|
—
|
||||||||||
|
Property and equipment,
net
|
220,408
|
1,919,412
|
729,131
|
(5,245
|
)
|
2,863,706
|
|||||||||||
|
Other
assets:
|
|||||||||||||||||
|
Equity
investments in unconsolidated affiliates
|
—
|
—
|
189,411
|
—
|
189,411
|
||||||||||||
|
Equity
investments in affiliates
|
2,123,169
|
29,649
|
—
|
(2,152,818
|
)
|
—
|
|||||||||||
|
Goodwill,
net
|
—
|
45,107
|
33,536
|
—
|
78,643
|
||||||||||||
|
Other
assets, net
|
48,822
|
41,669
|
22,919
|
(31,197
|
)
|
82,213
|
|||||||||||
|
Due
from subsidiaries/parent
|
73,867
|
64,775
|
—
|
(138,642
|
)
|
—
|
|||||||||||
|
$
|
2,983,131
|
$
|
2,399,719
|
$
|
859,364
|
$
|
(2,462,681
|
)
|
$
|
3,779,533
|
|||||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|||||||||||||||||
|
Current
liabilities:
|
|||||||||||||||||
|
Accounts
payable
|
$
|
58,451
|
$
|
79,128
|
$
|
17,878
|
$
|
—
|
$
|
155,457
|
|||||||
|
Accrued
liabilities
|
81,021
|
104,450
|
14,685
|
—
|
200,156
|
||||||||||||
|
Income
taxes payable
|
—
|
54,955
|
—
|
(54,955
|
)
|
—
|
|||||||||||
|
Current
maturities of long-term debt
|
4,326
|
—
|
33,837
|
(25,739
|
)
|
12,424
|
|||||||||||
|
Current
liabilities of discontinued operations
|
—
|
—
|
451
|
—
|
451
|
||||||||||||
|
Total
current liabilities
|
143,798
|
238,533
|
66,851
|
(80,694
|
)
|
368,488
|
|||||||||||
|
Long-term debt
|
1,233,504
|
—
|
114,811
|
—
|
1,348,315
|
||||||||||||
|
Deferred income taxes
|
137,662
|
222,528
|
90,676
|
(8,259
|
)
|
442,607
|
|||||||||||
|
Decommissioning
liabilities
|
—
|
176,657
|
5,742
|
—
|
182,399
|
||||||||||||
|
Other long-term
liabilities
|
924
|
2,495
|
766
|
77
|
4,262
|
||||||||||||
|
Due to parent
|
—
|
—
|
99,352
|
(99,352
|
)
|
—
|
|||||||||||
|
Total
liabilities
|
1,515,888
|
640,213
|
378,198
|
(188,228
|
)
|
2,346,071
|
|||||||||||
|
Convertible preferred
stock
|
6,000
|
—
|
—
|
—
|
6,000
|
||||||||||||
|
Total equity
|
1,461,243
|
1,759,506
|
481,166
|
(2,274,453
|
)
|
1,427,462
|
|||||||||||
|
$
|
2,983,131
|
$
|
2,399,719
|
$
|
859,364
|
$
|
(2,462,681
|
)
|
$
|
3,779,533
|
|||||||
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING BALANCE SHEETS
(in
thousands)
|
As
of December 31, 2008
|
|||||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||||
|
ASSETS
|
|||||||||||||||||
|
Current
assets:
|
|||||||||||||||||
|
Cash
and cash equivalents
|
$
|
148,704
|
$
|
4,983
|
$
|
69,926
|
$
|
—
|
$
|
223,613
|
|||||||
|
Accounts
receivable, net
|
125,882
|
97,300
|
204,674
|
—
|
427,856
|
||||||||||||
|
Unbilled
revenue
|
43,888
|
1,080
|
72,282
|
—
|
117,250
|
||||||||||||
|
Other
current assets
|
120,320
|
79,202
|
41,031
|
(68,464
|
)
|
172,089
|
|||||||||||
|
Current
assets of discontinued operations
|
—
|
—
|
19,215
|
—
|
19,215
|
||||||||||||
|
Total
current assets
|
438,794
|
182,565
|
407,128
|
(68,464
|
)
|
960,023
|
|||||||||||
|
Intercompany
|
78,395
|
100,662
|
(101,813
|
)
|
(77,244
|
)
|
—
|
||||||||||
|
Property and equipment,
net
|
168,054
|
2,007,807
|
1,247,060
|
(4,478
|
)
|
3,418,443
|
|||||||||||
|
Other
assets:
|
|||||||||||||||||
|
Equity
investments in unconsolidated affiliates
|
—
|
—
|
196,660
|
—
|
196,660
|
||||||||||||
|
Equity
investments in affiliates
|
2,331,924
|
31,374
|
—
|
(2,363,298
|
)
|
—
|
|||||||||||
|
Goodwill,
net
|
—
|
45,107
|
321,111
|
—
|
366,218
|
||||||||||||
|
Other
assets, net
|
48,734
|
37,967
|
68,035
|
(29,014
|
)
|
125,722
|
|||||||||||
|
$
|
3,065,901
|
$
|
2,405,482
|
$
|
2,138,181
|
$
|
(2,542,498
|
)
|
$
|
5,067,066
|
|||||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|||||||||||||||||
|
Current
liabilities:
|
|||||||||||||||||
|
Accounts
payable
|
$
|
99,197
|
$
|
139,074
|
$
|
107,856
|
$
|
(1,320
|
)
|
$
|
344,807
|
||||||
|
Accrued
liabilities
|
87,712
|
65,090
|
83,233
|
(4,356
|
)
|
231,679
|
|||||||||||
|
Income
taxes payable
|
(104,487
|
)
|
82,859
|
9,149
|
12,479
|
—
|
|||||||||||
|
Current
maturities of long-term debt
|
4,326
|
—
|
173,947
|
(84,733
|
)
|
93,540
|
|||||||||||
|
Current
liabilities of discontinued operations
|
—
|
—
|
2,772
|
—
|
2,772
|
||||||||||||
|
Total
current liabilities
|
86,748
|
287,023
|
376,957
|
(77,930
|
)
|
672,798
|
|||||||||||
|
Long-term debt
|
1,579,451
|
—
|
354,235
|
—
|
1,933,686
|
||||||||||||
|
Deferred income taxes
|
184,543
|
242,967
|
191,773
|
(3,779
|
)
|
615,504
|
|||||||||||
|
Decommissioning
liabilities
|
—
|
191,260
|
3,405
|
—
|
194,665
|
||||||||||||
|
Other long-term
liabilities
|
—
|
73,549
|
10,706
|
(2,618
|
)
|
81,637
|
|||||||||||
|
Due to parent
|
(100,528
|
)
|
(3,741)
|
126,013
|
(21,744
|
)
|
—
|
||||||||||
|
Total
liabilities
|
1,750,214
|
791,058
|
1,063,089
|
(106,071
|
)
|
3,498,290
|
|||||||||||
|
Convertible preferred
stock
|
55,000
|
—
|
—
|
—
|
55,000
|
||||||||||||
|
Total equity
|
1,260,687
|
1,614,424
|
1,075,092
|
(2,436,427
|
)
|
1,513,776
|
|||||||||||
|
$
|
3,065,901
|
$
|
2,405,482
|
$
|
2,138,181
|
$
|
(2,542,498
|
)
|
$
|
5,067,066
|
|||||||
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
(in
thousands)
|
Year
Ended December 31, 2009
|
|||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||
|
Net revenues
|
$
|
211,222
|
$
|
701,706
|
$
|
648,705
|
$
|
(99,946
|
)
|
$
|
1,461,687
|
||||
|
Cost of sales
|
162,225
|
484,802
|
521,689
|
(95,124
|
)
|
1,073,592
|
|||||||||
|
Oil and gas impairments
|
—
|
120,550
|
—
|
—
|
120,550
|
||||||||||
|
Exploration expense
|
—
|
24,383
|
—
|
—
|
24,383
|
||||||||||
|
Gross
profit
|
48,997
|
71,971
|
127,016
|
(4,822
|
)
|
243,162
|
|||||||||
|
Gain on oil
and gas derivative commodity contracts
|
—
|
89,485
|
—
|
—
|
89,485
|
||||||||||
|
Gain on sale of assets,
net
|
—
|
2,019
|
—
|
—
|
2,019
|
||||||||||
|
Selling and administrative
expenses
|
(52,101
|
)
|
(28,520
|
)
|
(53,919
|
)
|
3,689
|
(130,851
|
)
|
||||||
|
Income (loss) from
operations
|
(3,104
|
)
|
134,955
|
73,097
|
(1,133
|
)
|
203,815
|
||||||||
|
Equity
in earnings of unconsolidated affiliates
|
—
|
—
|
33,229
|
(900
|
)
|
32,329
|
|||||||||
|
Equity
in earnings (losses) of affiliates
|
145,340
|
(1,725
|
)
|
—
|
(143,615
|
)
|
—
|
||||||||
|
Gain
on sale of Cal Dive common stock
|
77,343
|
—
|
—
|
—
|
77,343
|
||||||||||
|
Net interest
expense and other
|
(18,188
|
)
|
(16,978
|
)
|
(15,341
|
)
|
988
|
(51,495
|
)
|
||||||
|
Income before income
taxes
|
201,391
|
116,252
|
90,985
|
(146,636
|
)
|
261,992
|
|||||||||
|
Provision for
income taxes
|
(43,417
|
)
|
(39,855
|
)
|
(13,571
|
)
|
1,021
|
(95,822
|
)
|
||||||
|
Income from continuing
operations
|
157,974
|
76,397
|
77,414
|
(145,615
|
)
|
166,170
|
|||||||||
|
Discontinued
operations, net of tax
|
99
|
|
—
|
9,482
|
—
|
9,581
|
|||||||||
|
Net income,
including noncontrolling interests
|
158,073
|
76,397
|
86,896
|
(145,615
|
)
|
175,751
|
|||||||||
|
Net
income applicable to noncontrolling interests
|
—
|
—
|
—
|
(19,697
|
)
|
(19,697
|
)
|
||||||||
|
Net income applicable to
Helix
|
158,073
|
76,397
|
86,896
|
(165,312
|
)
|
156,054
|
|||||||||
|
Preferred stock
dividends
|
(54,187
|
)
|
—
|
—
|
—
|
(54,187
|
)
|
||||||||
|
Net income
applicable to Helix common shareholders
|
$
|
103,886
|
$
|
76,397
|
$
|
86,896
|
$
|
(165,312
|
)
|
$
|
101,867
|
||||
|
Year
Ended December 31, 2008
|
|||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||
|
Net revenues
|
$
|
404,591
|
$
|
813,240
|
$
|
1,170,707
|
$
|
(274,464
|
)
|
$
|
2,114,074
|
||||
|
Cost of sales
|
347,433
|
554,628
|
837,685
|
(246,464
|
)
|
1,493,282
|
|||||||||
|
Oil and gas impairments
|
—
|
215,675
|
—
|
—
|
215,675
|
||||||||||
|
Exploration expense
|
—
|
32,926
|
—
|
—
|
32,926
|
||||||||||
|
Gross
profit
|
57,158
|
10,011
|
333,022
|
(28,000
|
)
|
372,191
|
|||||||||
|
Goodwill and
other intangible impairments
|
—
|
(704,311
|
)
|
—
|
—
|
(704,311
|
)
|
||||||||
|
Gain on oil
and gas derivative commodity contracts
|
—
|
21,599
|
—
|
—
|
21,599
|
||||||||||
|
Gain on sale of assets,
net
|
—
|
73,136
|
335
|
—
|
73,471
|
||||||||||
|
Selling and administrative
expenses
|
(42,194
|
)
|
(47,372
|
)
|
(91,974
|
)
|
4,368
|
(177,172
|
)
|
||||||
|
Income (loss) from
operations
|
14,964
|
(646,937
|
)
|
241,383
|
(23,632
|
)
|
(414,222
|
)
|
|||||||
|
Equity
in earnings of unconsolidated affiliates
|
—
|
—
|
31,854
|
—
|
31,854
|
||||||||||
|
Equity
in earnings (losses) of affiliates
|
(584,299
|
)
|
1,328
|
—
|
582,971
|
—
|
|||||||||
|
Net interest
expense and other
|
(21,939
|
)
|
(46,966
|
)
|
(42,285
|
)
|
92
|
(111,098
|
)
|
||||||
|
Income (loss) before income
taxes
|
(591,274
|
)
|
(692,575
|
)
|
230,952
|
559,431
|
(493,466
|
)
|
|||||||
|
(Provision)
benefit for income taxes
|
(30,412
|
)
|
(2,909
|
)
|
(62,754
|
)
|
9,296
|
(86,779
|
)
|
||||||
|
Income
(loss)from continuing operations
|
(621,686
|
)
|
(695,484
|
)
|
168,198
|
568,727
|
(580,245
|
)
|
|||||||
|
Discontinued
operations, net of tax
|
—
|
—
|
(9,812
|
)
|
—
|
(9,812
|
)
|
||||||||
|
Net income
(loss), including noncontrolling interests
|
(621,686
|
)
|
(695,484
|
)
|
158,386
|
568,727
|
(590,057
|
)
|
|||||||
|
Net
income (loss) applicable to noncontrolling interests
|
—
|
—
|
—
|
(45,873
|
)
|
(45,873
|
)
|
||||||||
|
Net income
(loss) applicable to Helix
|
(621,686
|
) |
(695,484
|
)
|
158,386
|
522,854
|
(635,930
|
)
|
|||||||
|
Preferred stock
dividends
|
(3,192
|
)
|
—
|
—
|
—
|
(3,192
|
)
|
||||||||
|
Net income
(loss) applicable to Helix common shareholders
|
$
|
(624,878
|
)
|
$
|
(695,484
|
)
|
$
|
158,386
|
$
|
522,854
|
$
|
(639,122
|
)
|
||
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
(in
thousands)
|
Year
Ended December 31, 2007
|
|||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||
|
Net revenues
|
$
|
262,007
|
$
|
769,648,
|
$
|
874,324
|
$
|
(173,559
|
)
|
$
|
1,732,420
|
||||
|
Cost of sales
|
201,001
|
514,653
|
568,480
|
(148,418
|
)
|
1,135,716
|
|||||||||
|
Oil and gas impairments
|
—
|
64,072
|
—
|
—
|
64,072
|
||||||||||
|
Exploration expense
|
—
|
26,725
|
—
|
—
|
26,725
|
||||||||||
|
Gross
profit
|
61,006
|
164,198
|
305,844
|
(25,141
|
)
|
505,907
|
|||||||||
|
Gain on sale of assets,
net
|
1,960
|
42,566
|
5,842
|
—
|
50,368
|
||||||||||
|
Selling and administrative
expenses
|
(38,063
|
)
|
(44,940
|
)
|
(65,126
|
)
|
3,133
|
(144,996
|
)
|
||||||
|
Income from operations
|
24,903
|
161,824
|
246,560
|
(22,008
|
)
|
411,279
|
|||||||||
|
Equity
in earnings of unconsolidated affiliates
|
—
|
—
|
19,573
|
—
|
19,573
|
||||||||||
|
Equity
in earnings (losses) of affiliates
|
219,280
|
15,140
|
—
|
(234,420
|
)
|
—
|
|||||||||
|
Gain
on sale of Cal Dive common stock
|
151,696
|
—
|
—
|
—
|
151,696
|
||||||||||
|
Net interest
expense and other
|
7,539
|
(49,064
|
)
|
(21,178
|
)
|
(4,344
|
)
|
(67,047
|
)
|
||||||
|
Income before income
taxes
|
403,418
|
127,900
|
244,955
|
(260,772
|
)
|
515,501
|
|||||||||
|
Provision for
income taxes
|
(70,592
|
)
|
(39,871
|
)
|
(70,623
|
)
|
9,224
|
(171,862
|
)
|
||||||
|
Income from continuing
operations
|
332,826
|
88,029
|
174,332
|
(251,548
|
)
|
343,639
|
|||||||||
|
Discontinued
operations, net of tax
|
—
|
—
|
1,347
|
—
|
1,347
|
||||||||||
|
Net income,
including noncontrolling interests
|
332,826
|
88,029
|
175,679
|
(251,548
|
)
|
344,986
|
|||||||||
|
Net
income applicable to noncontrolling interests
|
—
|
—
|
(113
|
)
|
(29,175
|
)
|
(29,288
|
)
|
|||||||
|
Net income applicable to
Helix
|
332,826
|
88,029
|
175,566
|
(280,723
|
)
|
315,698
|
|||||||||
|
Preferred stock
dividends
|
(3,716
|
)
|
—
|
—
|
—
|
(3,716
|
)
|
||||||||
|
Net income
applicable to Helix common shareholders
|
$
|
329,110
|
$
|
88,029
|
$
|
175,566
|
$
|
(280,723
|
)
|
$
|
311,982
|
||||
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
For
the Year Ended December 31, 2009
|
|||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||
|
(in
thousands)
|
|||||||||||||||
|
Cash flow
from operating activities:
|
|||||||||||||||
|
Net
income (loss), including noncontrolling interests
|
$
|
158,073
|
$
|
76,397
|
$
|
86,896
|
$
|
(145,615
|
)
|
$
|
175,751
|
||||
|
Adjustments
to reconcile net income (loss)
to
net cash provided by (used in)
operating
activities:
|
|||||||||||||||
|
Equity
in earnings of unconsolidated
affiliates
|
—
|
—
|
(7,220
|
)
|
899
|
(6,321
|
)
|
||||||||
|
Equity
in earnings of affiliates
|
(145,340
|
)
|
1,725
|
—
|
143,615
|
—
|
|||||||||
|
Other
adjustments
|
26,633
|
163,451
|
80,281
|
(17,987
|
)
|
252,378
|
|||||||||
|
Net
cash provided by (used in) operating activities
|
39,366
|
241,573
|
159,957
|
(19,088
|
)
|
421,808
|
|||||||||
|
Net
cash provided by discontinued operations
|
—
|
—
|
(6,261
|
)
|
—
|
(6,261
|
)
|
||||||||
|
Net
cash provided by (used in)
operating
activities
|
39,366
|
241,573
|
153,696
|
(19,088
|
)
|
415,547
|
|||||||||
|
Cash flows
from investing activities:
|
|||||||||||||||
|
Capital
expenditures
|
(35,657
|
)
|
(245,354
|
)
|
(142,362
|
)
|
—
|
(423,373
|
)
|
||||||
|
Acquisition
of businesses, net of
cash
acquired
|
—
|
—
|
—
|
—
|
—
|
||||||||||
|
Investments
in equity investments
|
—
|
—
|
(1,657
|
)
|
—
|
(1,657
|
)
|
||||||||
|
Distributions
from equity investments, net
|
—
|
—
|
6,742
|
—
|
6,742
|
||||||||||
|
Increases in
restricted cash
|
—
|
(6
|
)
|
—
|
—
|
(6
|
)
|
||||||||
|
Proceeds
from sale of Cal Dive common stock
|
504,168
|
—
|
(112,995
|
)
|
(86,000
|
)
|
305,173
|
||||||||
|
Proceeds
from sales of property
|
—
|
23,717
|
—
|
—
|
23,717
|
||||||||||
|
Net
cash provided by (used in)
investing activities
|
468,511
|
(221,643
|
)
|
(250,272
|
)
|
(86,000
|
)
|
(89,404
|
)
|
||||||
|
Net
cash provided by discontinued operations
|
—
|
—
|
20,872
|
—
|
20,872
|
||||||||||
|
Net
cash provided by ( used in) investing activities
|
468,511
|
(221,643
|
)
|
(229,400
|
)
|
(86,000
|
)
|
(68,532
|
)
|
||||||
|
Cash flows
from financing activities:
|
|||||||||||||||
|
Borrowings
on revolvers
|
—
|
—
|
100,000
|
—
|
100,000
|
||||||||||
|
Repayments
on revolvers
|
(349,500
|
)
|
—
|
—
|
—
|
(349,500
|
)
|
||||||||
|
Repayments
of debt
|
(4,326
|
)
|
—
|
(24,214
|
)
|
—
|
(28,540
|
)
|
|||||||
|
Deferred
financing costs
|
(6,970
|
)
|
—
|
—
|
—
|
(6,970
|
)
|
||||||||
|
Preferred
stock dividends paid
|
(645
|
)
|
—
|
—
|
—
|
(645
|
)
|
||||||||
|
Repurchase
of common stock
|
(13,995
|
)
|
—
|
(86,000
|
)
|
86,000
|
(13,995
|
)
|
|||||||
|
Excess
tax benefit from
stock-based compensation
|
895
|
—
|
—
|
—
|
895
|
||||||||||
|
Exercise of
stock options, net
|
176
|
—
|
—
|
—
|
176
|
||||||||||
|
Intercompany
financing
|
(23,474
|
)
|
(22,391
|
)
|
26,777
|
19,088
|
—
|
||||||||
|
Net
cash provided by
(used
in) financing activities
|
(397,839
|
)
|
(22,391
|
)
|
16,563
|
105,088
|
(298,579
|
)
|
|||||||
|
Effect of
exchange rate changes on
cash and
cash equivalents
|
—
|
—
|
(1,376
|
)
|
—
|
(1,376
|
)
|
||||||||
|
Net increase
(decrease) in cash
and cash
equivalents
|
110,038
|
(2,461
|
)
|
(60,517
|
)
|
—
|
47,060
|
||||||||
|
Cash and cash
equivalents:
|
|||||||||||||||
|
Balance,
beginning of year
|
148,704
|
4,983
|
69,926
|
—
|
223,613
|
||||||||||
|
Balance, end
of year
|
$
|
258,742
|
$
|
2,522
|
$
|
9,409
|
$
|
—
|
$
|
270,673
|
|||||
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
For
the Year Ended December 31, 2008
|
|||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||
|
(in
thousands)
|
|||||||||||||||
|
Cash flow
from operating activities:
|
|||||||||||||||
|
Net
income (loss), including noncontrolling interests
|
$
|
(621,686
|
)
|
$
|
(695,484
|
)
|
$
|
158,386
|
$
|
568,727
|
$
|
(590,057
|
)
|
||
|
Adjustments
to reconcile net income (loss)
to
net cash provided by (used in)
operating
activities:
|
|||||||||||||||
|
Equity
in earnings of unconsolidated
affiliates
|
—
|
—
|
2,846
|
—
|
2,846
|
||||||||||
|
Equity
in earnings of affiliates
|
584,299
|
(1,328
|
)
|
—
|
(582,971
|
)
|
—
|
||||||||
|
Other
adjustments
|
(48,995
|
)
|
967,933
|
107,708
|
(5,021
|
)
|
1,021,625
|
||||||||
|
Net
cash provided by (used in) operating activities
|
(86,382
|
)
|
271,121
|
268,940
|
(19,265
|
)
|
434,414
|
||||||||
|
Net
cash provided by discontinued operations
|
—
|
—
|
3,305
|
—
|
3,305
|
||||||||||
|
Net
cash provided by (used in)
operating
activities
|
(86,382
|
)
|
271,121
|
272,245
|
(19,265
|
)
|
437,719
|
||||||||
|
Cash flows
from investing activities:
|
|||||||||||||||
|
Capital
expenditures
|
(75,003
|
)
|
(513,024
|
)
|
(267,027
|
)
|
—
|
(855,054
|
)
|
||||||
|
Acquisition
of businesses, net of
cash
acquired
|
—
|
—
|
—
|
—
|
—
|
||||||||||
|
Investments
in equity investments
|
—
|
—
|
(846
|
)
|
—
|
(846
|
)
|
||||||||
|
Distributions
from equity investments, net
|
—
|
—
|
11,586
|
—
|
11,586
|
||||||||||
|
Increases in
restricted cash
|
—
|
(614
|
)
|
—
|
—
|
(614
|
)
|
||||||||
|
Proceeds
from insurance
|
—
|
13,200
|
—
|
—
|
13,200
|
||||||||||
|
Proceeds
from sales of property
|
—
|
271,758
|
2,472
|
—
|
274,230
|
||||||||||
|
Net
cash used in investing activities
|
(75,003
|
)
|
(228,680
|
)
|
(253,815
|
)
|
—
|
(557,498
|
)
|
||||||
|
Net
cash used in discontinued operations
|
—
|
—
|
(476
|
)
|
—
|
(476
|
)
|
||||||||
|
Net
cash used in investing activities
|
(75,003
|
)
|
(228,680
|
)
|
(254,291
|
)
|
—
|
(557,974
|
)
|
||||||
|
Cash flows
from financing activities:
|
|||||||||||||||
|
Borrowings
on revolvers
|
1,021,500
|
—
|
61,100
|
—
|
1,082,600
|
||||||||||
|
Repayments
on revolvers
|
(690,000
|
)
|
—
|
(61,100
|
)
|
—
|
(751,100
|
)
|
|||||||
|
Repayments
of debt
|
(4,326
|
)
|
—
|
(64,014
|
)
|
—
|
(68,340
|
)
|
|||||||
|
Deferred
financing costs
|
(1,796
|
)
|
—
|
—
|
—
|
(1,796
|
)
|
||||||||
|
Capital
lease payments
|
—
|
—
|
(1,505
|
)
|
—
|
(1,505
|
)
|
||||||||
|
Preferred
stock dividends paid
|
(3,192
|
)
|
—
|
—
|
—
|
(3,192
|
)
|
||||||||
|
Repurchase
of common stock
|
(3,925
|
)
|
—
|
—
|
—
|
(3,925
|
)
|
||||||||
|
Excess
tax benefit from
stock-based compensation
|
1,335
|
—
|
—
|
—
|
1,335
|
||||||||||
|
Exercise of
stock options, net
|
2,139
|
—
|
—
|
—
|
2,139
|
||||||||||
|
Intercompany
financing
|
(15,153
|
)
|
(40,067
|
)
|
35,955
|
19,265
|
—
|
||||||||
|
Net
cash provided by
(used
in) financing activities
|
306,582
|
(40,067
|
)
|
(29,564
|
)
|
19,265
|
256,216
|
||||||||
|
Effect of
exchange rate changes on
cash and
cash equivalents
|
—
|
—
|
(1,903
|
)
|
—
|
(1,903
|
)
|
||||||||
|
Net increase
(decrease) in cash
and cash
equivalents
|
145,197
|
2,374
|
(13,513
|
)
|
—
|
134,058
|
|||||||||
|
Cash and cash
equivalents:
|
|||||||||||||||
|
Balance,
beginning of year
|
3,507
|
2,609
|
83,439
|
—
|
89,555
|
||||||||||
|
Balance, end
of year
|
$
|
148,704
|
$
|
4,983
|
$
|
69,926
|
$
|
—
|
$
|
223,613
|
|||||
HELIX
ENERGY SOLUTIONS GROUP, INC.
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
For
the Year Ended December 31, 2007
|
|||||||||||||||
|
Helix
|
Guarantors
|
Non-Guarantors
|
Consolidating
Entries
|
Consolidated
|
|||||||||||
|
(in
thousands)
|
|||||||||||||||
|
Cash flow
from operating activities:
|
|||||||||||||||
|
Net
income (loss), including noncontrolling interests
|
$
|
332,826
|
$
|
88,029
|
$
|
175,679
|
$
|
(251,548
|
)
|
$
|
344,986
|
||||
|
Adjustments
to reconcile net income (loss)
to
net cash provided by (used in)
operating
activities:
|
|||||||||||||||
|
Equity
in earnings of unconsolidated
affiliates
|
—
|
—
|
11,538
|
—
|
11,538
|
||||||||||
|
Equity
in earnings of affiliates
|
(219,280
|
)
|
(15,139
|
)
|
—
|
234,419
|
—
|
||||||||
|
Other
adjustments
|
(268,156
|
)
|
297,948
|
(135,511
|
)
|
169,970
|
64,251
|
||||||||
|
Net
cash provided by (used in) operating activities
|
(154,610
|
)
|
370,838
|
51,706
|
152,841
|
420,775
|
|||||||||
|
Net
cash provided by discontinued operations
|
—
|
—
|
(4,449
|
)
|
—
|
(4,449
|
)
|
||||||||
|
Net
cash provided by (used in)
operating
activities
|
(154,610
|
)
|
370,838
|
47,257
|
152,841
|
416,326
|
|||||||||
|
Cash flows
from investing activities:
|
|||||||||||||||
|
Capital
expenditures
|
(81,577
|
)
|
(642,364
|
)
|
(218,440
|
)
|
—
|
(942,381
|
)
|
||||||
|
Acquisition
of businesses, net of
cash
acquired
|
—
|
—
|
(147,498
|
)
|
—
|
(147,498
|
)
|
||||||||
|
Sale of
short-term investments
|
285,395
|
—
|
—
|
—
|
285,395
|
||||||||||
|
Investments
in equity investments
|
—
|
—
|
(17,459
|
)
|
—
|
(17,459
|
)
|
||||||||
|
Distributions
from equity investments, net
|
—
|
—
|
6,679
|
—
|
6,679
|
||||||||||
|
Increases in
restricted cash
|
—
|
(1,112
|
)
|
—
|
—
|
(1,112
|
)
|
||||||||
|
Proceeds
from sales of property
|
—
|
53,547
|
24,526
|
—
|
78,073
|
||||||||||
|
Other,
net
|
—
|
(136
|
)
|
—
|
—
|
(136
|
)
|
||||||||
|
Net
cash used in investing activities
|
203,818
|
(590,065
|
)
|
(352,192
|
)
|
—
|
(738,439
|
)
|
|||||||
|
Net
cash used in discontinued operations
|
—
|
—
|
(1,215
|
)
|
—
|
(1,215
|
)
|
||||||||
|
Net
cash provided by (used in)
investing
activities
|
203,818
|
(590,065
|
)
|
(353,407
|
)
|
—
|
(739,654
|
)
|
|||||||
|
Cash flows
from financing activities:
|
|||||||||||||||
|
Borrowings
on revolvers
|
472,800
|
—
|
31,500
|
—
|
504,300
|
||||||||||
|
Repayments
on revolvers
|
(454,800
|
)
|
—
|
(332,668
|
)
|
—
|
(787,468
|
)
|
|||||||
|
Borrowings
under debt
|
550,000
|
—
|
380,000
|
—
|
930,000
|
||||||||||
|
Repayments
of debt
|
(405,408
|
)
|
—
|
(3,823
|
)
|
—
|
(409,231
|
)
|
|||||||
|
Deferred
financing costs
|
(11,377
|
)
|
—
|
(5,788
|
)
|
—
|
(17,165
|
)
|
|||||||
|
Capital
lease payments
|
—
|
—
|
(2,519
|
)
|
—
|
(2,519
|
)
|
||||||||
|
Preferred
stock dividends paid
|
(3,716
|
)
|
—
|
—
|
—
|
(3,716
|
)
|
||||||||
|
Repurchase
of common stock
|
(9,904
|
)
|
—
|
—
|
—
|
(9,904
|
)
|
||||||||
|
Excess
tax benefit from
stock-based compensation
|
580
|
—
|
—
|
—
|
580
|
||||||||||
|
Exercise of
stock options, net
|
1,568
|
—
|
—
|
—
|
1,568
|
||||||||||
|
Intercompany
financing
|
(327,933
|
)
|
214,146
|
266,628
|
(152,841
|
)
|
—
|
||||||||
|
Net
cash provided by
(used
in) financing activities
|
(188,190
|
)
|
214,146
|
333,330
|
(152,841
|
)
|
206,445
|
||||||||
|
Effect of
exchange rate changes on
cash and
cash equivalents
|
—
|
—
|
174
|
—
|
174
|
||||||||||
|
Net increase
(decrease) in cash
and cash
equivalents
|
(138,982
|
)
|
(5,081
|
)
|
27,354
|
—
|
(116,709
|
)
|
|||||||
|
Cash and cash
equivalents:
|
|||||||||||||||
|
Balance,
beginning of year
|
142,489
|
7,690
|
56,085
|
—
|
206,264
|
||||||||||
|
Balance, end
of year
|
$
|
3,507
|
$
|
2,609
|
$
|
83,439
|
$
|
—
|
$
|
89,555
|
|||||
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial
Disclosure.
None.
Item 9A. Controls and Procedures.
(a) Evaluation
of disclosure controls and procedures. Our management, with
the participation of our principal executive officer and principal financial
officer, evaluated the effectiveness of our disclosure controls and procedures,
as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the
Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end
of the fiscal year ended December 31, 2009. Based on this
evaluation, the principal executive officer and the principal financial officer
conclude that our disclosure controls and procedures were effective as of the
end of the fiscal year ended December 31, 2009 to ensure that information that
is required to be disclosed by us in the reports we file or submit under the
Exchange Act is (i) identified, recorded, processed, summarized and
reported, on a timely basis and (ii) accumulated and communicated to our
management, as appropriate, to allow timely decisions regarding required
disclosure.
(b) Changes
in internal control over financial reporting. There have been
no changes in our internal control over financial reporting, as defined in
Rule 13a-15(f) of the Securities Exchange Act, in the period covered by
this report that have materially affected, or are reasonably likely to
materially affect, our internal control over financial
reporting.
(c) Changes
in Internal Control. There was not any change in our internal control
over financial reporting that occurred during the fourth quarter of fiscal 2009
that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
Management’s Report
on Internal Control Over Financial Reporting and the Report of Independent
Registered Public Accounting Firm on Internal Control Over Financial Reporting
thereon are set forth in Part II, Item 8 of this report on
Form 10-K on page 74 and page 76, respectively.
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate
Governance.
Except as set forth
below, the information required by this Item is incorporated by reference to our
definitive Proxy Statement to be filed pursuant to Regulation 14A under the
Securities Act of 1934 in connection with our 2010 Annual Meeting of
Shareholders to be held on May 12, 2010. See also “Executive Officers of the
Registrant” appearing in Part I of this Report.
Code
of Ethics
We
have adopted a Code
of Business Conduct and Ethics for all directors, officers and employees
as well as a Code
of Ethics for Chief Executive Officer and Senior Financial
Officers specific to those officers. Copies of these documents are
available at our Website www.helixesg.com under Corporate
Governance. Interested parties may also request a free copy of these
documents from:
Helix Energy
Solutions Group, Inc.
ATTN: Corporate
Secretary
400 N. Sam
Houston Parkway E., Suite 400
Houston, Texas
77060
Item 11. Executive Compensation.
The information
required by this Item is incorporated by reference to our definitive Proxy
Statement to be filed pursuant to Regulation 14A under the Securities Act
of 1934 in connection with our 2010 Annual Meeting of Shareholders to be held on
May 12, 2010.
Item 12. Security Ownership of Certain Beneficial Owners and
Management and
Related Stockholder Matters.
The information
required by this Item is incorporated by reference to our definitive Proxy
Statement to be filed pursuant to Regulation 14A under the Securities Act
of 1934 in connection with our 2010 Annual Meeting of Shareholders to be held on
May 12, 2010.
Item 13. Certain Relationships and Related
Transactions.
The information
required by this Item is incorporated by reference to our definitive Proxy
Statement to be filed pursuant to Regulation 14A under the Securities Act
of 1934 in connection with our 2010 Annual Meeting of Shareholders to be held on
May 12, 2010.
Item 14. Principal Accounting Fees and
Services.
The information
required by this Item is incorporated by reference to our definitive Proxy
Statement to be filed pursuant to Regulation 14A under the Securities Act
of 1934 in connection our 2010 Annual Meeting of Shareholders to be held on May
12, 2010.
PART IV
Item 15. Exhibits and Financial Statement
Schedules.
(1) Financial
Statements.
The following
financial statements included on pages 74 through 143 in this Annual Report
are for the fiscal year ended December 31, 2009.
|
•
|
Management’s
Report on Internal Control Over Financial Reporting
|
||
|
•
|
Report of
Independent Registered Public Accounting Firm
|
||
|
•
|
Report of
Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting
|
||
|
•
|
Consolidated
Balance Sheets as of December 31, 2009 and 2008
|
||
|
•
|
Consolidated
Statements of Operations for the Years Ended December 31, 2009, 2008
and 2007
|
||
|
•
|
Consolidated
Statements of Shareholders’ Equity for the Years Ended December 31,
2009, 2008 and 2007
|
||
|
•
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2009, 2008
and 2007
|
||
|
•
|
Notes to
Consolidated Financial Statements.
|
All financial
statement schedules are omitted because the information is not required or
because the information required is in the financial statements or notes
thereto.
(2) Exhibits.
Pursuant to
Item 601(b)(4)(iii), the Registrant agrees to forward to the commission,
upon request, a copy of any instrument with respect to long-term debt not
exceeding 10% of the total assets of the Registrant and its consolidated
subsidiaries. Reference is made to Exhibit listing beginning on page
147 hereof.
Pursuant to the
requirements of section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
HELIX ENERGY SOLUTIONS GROUP,
INC.
|
By:
|
/s/ ANTHONY
TRIPODO
|
Anthony Tripodo
Executive Vice President
and
Chief Financial
Officer
February 26,
2010
Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities
and on the dates indicated.
|
Signature
|
Title
|
Date
|
|
/s/ OWEN
KRATZ
Owen
Kratz
|
President,
Chief Executive Officer and
Director
(principal executive officer)
|
February 26,
2010
|
|
/s/ ANTHONY
TRIPODO
Anthony
Tripodo
|
Executive
Vice President and Chief
Financial
Officer (principal financial officer)
|
February 26,
2010
|
|
/s/ LLOYD
A.
HAJDIK
Lloyd A.
Hajdik
|
Senior Vice
President — Finance and Chief
Accounting
Officer (principal
accounting
officer)
|
February 26,
2010
|
|
/s/ GORDON
F.
AHALT
Gordon F.
Ahalt
|
Director
|
February 26,
2010
|
|
/s/ BERNARD
J. DUROC-DANNER
Bernard J.
Duroc-Danner
|
Director
|
February 26,
2010
|
|
/s/ JOHN V.
LOVOI
John V.
Lovoi
|
Director
|
February 26,
2010
|
|
/s/ T.
WILLIAM
PORTER
T. William
Porter
|
Director
|
February 26,
2010
|
|
/s/ NANCY
K. QUINN
Nancy K.
Quinn
|
Director
|
February 26,
2010
|
|
/s/ WILLIAM L.
TRANSIER
William L.
Transier
|
Director
|
February 26,
2010
|
|
/s/ JAMES
A. WATT
James A.
Watt
|
Director
|
February 26,
2010
|
INDEX
TO EXHIBITS
|
Exhibits
|
|
|
2.1
|
Agreement and
Plan of Merger dated January 22, 2006, among Cal Dive International,
Inc. and Remington Oil and Gas Corporation, incorporated by reference to
Exhibit 2.1 to the Current Report on Form 8-K/A, filed by the
registrant with the Securities and Exchange Commission on January 25,
2006 (the “Form 8-K/A”).
|
|
2.2
|
Amendment
No. 1 to Agreement and Plan of Merger dated January 24, 2006, by
and among, Cal Dive International, Inc., Cal Dive Merger — Delaware,
Inc. and Remington Oil and Gas Corporation, incorporated by reference to
Exhibit 2.2 to the Form 8-K/A.
|
|
3.1
|
2005 Amended
and Restated Articles of Incorporation, as amended, of registrant,
incorporated by reference to Exhibit 3.1 to the Current Report on
Form 8-K filed by registrant with the Securities and Exchange
Commission on March 1, 2006.
|
|
3.2
|
Second
Amended and Restated By-Laws of Helix, as amended, incorporated by
reference to Exhibit 3.1 to the Current Report on Form 8-K,
filed by the registrant with the Securities and Exchange Commission on
September 28, 2006.
|
|
3.3
|
Certificate
of Rights and Preferences for Series A-1 Cumulative Convertible
Preferred Stock, incorporated by reference to Exhibit 3.1 to the
Current Report on Form 8-K, filed by registrant with the Securities
and Exchange Commission on January 22, 2003 (the “2003
Form 8-K”).
|
|
3.4
|
Certificate
of Rights and Preferences for Series A-2 Cumulative Convertible
Preferred Stock, incorporated by reference to Exhibit 3.1 to the
Current Report on Form 8-K, filed by registrant with the Securities
and Exchange Commission on June 28, 2004 (the “2004
Form 8-K”).
|
|
4.1
|
Credit
Agreement dated July 3, 2006 by and among Helix Energy Solutions
Group, Inc., and Bank of America, N.A., as administrative agent and as
lender, together with the other lender parties thereto, incorporated by
reference to Exhibit 4.1 to the registrant’s Current Report on
Form 8-K, filed by the registrant with the Securities and Exchange
Commission on July 5, 2006.
|
|
4.2
|
Amendment
No. 1 to Credit Agreement, dated as of November 29, 2007, by and
among Helix, as borrower, Bank of America, N.A., as administrative agent,
and the lenders named thereto incorporated by reference to
Exhibit 10.3 to the December 2007 8-K.
|
|
4.3
|
Amendment No.
2 to Credit Agreement, dated as of October 9, 2009, by and among Helix, as
borrower, Bank of America, N.A., as administrative agent, and the lenders
named thereto, incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K, filed by the registrant with the Securities and
Exchange Commission on October 13, 2009.
|
|
4.4
|
Amendment No.
3 to Credit Agreement, dated as of February 19, 2010, by and among Helix,
as borrower, Bank of America, N.A., as administrative agent, and the
lenders named thereto. Incorporated by reference to Exhibit 10.1 to the
registrant’s Current Report on Form 8-K, filed by the registrant with the
Securities and Exchange Commission on February 24,
2010.
|
|
4.5
|
Form of
Common Stock certificate, incorporated by reference to Exhibit 4.7 to
the Form 8-A filed by the Registrant with the Securities and Exchange
Commission on June 30, 2006.
|
|
4.6
|
Credit
Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated,
Citibank N.A. and Citibank International LLC dated as of August 16,
2000, incorporated by reference to Exhibit 4.4 to the 2001
Form 10-K.
|
|
4.7
|
Amendment
No. 1 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO
Incorporated, Citibank N.A. and Citibank International LLC dated as of
January 25, 2002, incorporated by reference to Exhibit 4.9 to
the Form 10-K/A filed with the Securities and Exchange Commission on
April 8, 2003.
|
|
4.8
|
Amendment
No. 2 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO
Incorporated, Citibank N.A. and Citibank International LLC dated as of
November 15, 2002, incorporated by reference to Exhibit 4.4 to
the Form S-3 filed with the Securities and Exchange Commission on
February 26, 2003.
|
|
4.9
|
First Amended
and Restated Agreement dated January 17, 2003, but effective as of
December 31, 2002, by and between Helix Energy Solutions Group, Inc.
and Fletcher International, Ltd., incorporated by reference to
Exhibit 10.1 to the 2003 Form 8-K.
|
|
4.10
|
Amendment
No. 3 Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO
Incorporated, Citibank N.A. and Citibank International LLC dated as of
July 31, 2003, incorporated by reference to Exhibit 4.12 to
Annual Report for the year ended December 31, 2004, filed by the
registrant with the Securities Exchange Commission on March 16, 2005
(the “2004 10-K”).
|
|
4.11
|
Amendment
No. 4 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO
Incorporated, Citibank N.A. and Citibank International LLC dated as of
December 15, 2004 , incorporated by reference to Exhibit 4.13 to
the 2004 10-K.
|
|
4.12
|
Indenture
relating to the 3.25% Convertible Senior Notes due 2025 dated as of
March 30, 2005, between Cal Dive International, Inc. and JPMorgan
Chase Bank, National Association, as Trustee., incorporated by reference
to Exhibit 4.1 to the Current Report on Form 8-K, filed by the
registrant with the Securities and Exchange Commission on April 4,
2005 (the “April 2005 8-K”).
|
|
4.13
|
Form of
3.25% Convertible Senior Note due 2025 (filed as Exhibit A to
Exhibit 4.15).
|
|
4.14
|
Registration
Rights Agreement dated as of March 30, 2005, between Cal Dive
International, Inc. and Banc of America Securities LLC, as representative
of the initial purchasers, incorporated by reference to Exhibit 4.3
to the April 2005 8-K.
|
|
4.15
|
Trust Indenture,
dated as of August 16, 2000, between Cal Dive I-Title XI, Inc.
and Wilmington Trust, as Indenture Trustee, incorporated by reference to
Exhibit 4.1 to the Current Report on Form 8-K, filed by the
registrant with the Securities and Exchange Commission on October 6,
2005 (the “October 2005 8-K”).
|
|
4.16
|
Supplement
No. 1 to Trust Indenture, dated as of January 25, 2002,
between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture
Trustee, incorporated by reference to Exhibit 4.2 to the October 2005
8-K.
|
|
4.17
|
Supplement
No. 2 to Trust Indenture, dated as of November 15, 2002,
between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture
Trustee, incorporated by reference to Exhibit 4.3 to the October 2005
8-K.
|
|
4.18
|
Supplement
No. 3 to Trust Indenture, dated as of December 14, 2004,
between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture
Trustee, incorporated by reference to Exhibit 4.4 to the October 2005
8-K.
|
|
4.19
|
Supplement
No. 4 to Trust Indenture, dated September 30, 2005, between
Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee,
incorporated by reference to Exhibit 4.5 to the October 2005
8-K.
|
|
4.20
|
Form of
United States Government Guaranteed Ship Financing Bonds, Q4000
Series 4.93% Sinking Fund Bonds Due February 1, 2027 (filed
as Exhibit A to Exhibit 4.21).
|
|
4.21
|
Form of Third
Amended and Restated Promissory Note to United States of America,
incorporated by reference to Exhibit 4.6 to the October 2005
8-K.
|
|
4.22
|
Term Loan
Agreement by and among Kommandor LLC, Nordea Bank Norge ASA, as arranger
and agent, Nordea Bank Finland Plc, as swap bank, together with the other
lender parties thereto, effective as of June 13, 2007 incorporated by
reference to Exhibit 4.7 to the registrants Quarterly Report on
Form 10-Q for the fiscal quarter ended June 30, 2007, file by
the registrant with the Securities and Exchange Commission on
August 3, 2007.
|
|
4.23
|
Indenture,
dated as of December 21, 2007, by and among Helix Energy Solutions
Group, Inc., the Guarantors and Wells Fargo Bank, N.A. incorporated by
reference to Exhibit 4.1 to the registrants Current Report on
Form 8-K, filed by the registrant with the Securities and Exchange
Commission on December 21, 2007 (the “December 2007
8-K”).
|
|
10.1
|
1995 Long
Term Incentive Plan, as amended, incorporated by reference to
Exhibit 10.3 to the Form S-1.
|
|
10.2
|
Amendment to
1995 Long Term Incentive Plan of Helix Energy Solutions Group,
Inc.
|
|
10.3
|
2009
Long-Term Incentive Cash Plan of Helix Energy Solutions Group, Inc.,
incorporated by reference to Exhibit 10.1 to the Current Report on Form
8-K, filed by the registrant with the Securities and Exchange Commission
on January 6, 2009 (the “January 2009 8-K”).
|
|
10.4
|
Form of Award
Letter related to the 2009 Long-Term Incentive Cash Plan, incorporated by
reference to Exhibit 10.2 to the January 2009 8-K.
|
|
10.5
|
Employment
Agreement between Owen Kratz and Company dated February 28, 1999,
incorporated by reference to Exhibit 10.5 to the Annual Report for
the fiscal year ended December 31, 1998, filed by the registrant with
the Securities and Exchange Commission on March 31, 1999 (the “1998
Form 10-K”).
|
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10.6
|
Employment
Agreement between Owen Kratz and Company dated November 17, 2008,
incorporated by reference to Exhibit 10.1 to the Current Report on Form
8-K, filed by the registrant with the Securities and Exchange Commission
on November 19, 2008 (the “November 2008 8-K”).
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|
10.7
|
Employment
Agreement between Martin R. Ferron and Company dated February 28,
1999, incorporated by reference to Exhibit 10.6 of the 1998
Form 10-K.
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|
10.8
|
Employment
Agreement between A. Wade Pursell and Company dated January 1, 2002,
incorporated by reference to Exhibit 10.7 of the 2001
Form 10-K.
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|
10.9
|
Helix 2005
Long Term Incentive Plan, including the Form of Restricted Stock Award
Agreement, incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K, filed by the registrant with the Securities and
Exchange Commission on May 12, 2005.
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|
10.10
|
Amendment to
2005 Long Term Incentive Plan of Helix Energy Solutions Group,
Inc.
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|
10.11
|
Employment
Agreement by and between Helix and Bart H. Heijermans, effective as of
September 1, 2005, incorporated by reference to Exhibit 10.1 to
the Current Report on Form 8-K, filed by the registrant with the
Securities and Exchange Commission on September 1,
2005.
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|
10.12
|
Employment
Agreement between Bart H. Heijermans and Company dated November 17, 2008,
incorporated by reference to Exhibit 10.2 to the November 2008
8-K.
|
|
10.13
|
Employment
Agreement between Alisa B. Johnson and Company dated September 18,
2006, incorporated by reference to Exhibit 10.2 to the 2006
Form 10-Q.
|
|
10.14
|
Employment
Agreement between Alisa B. Johnson and Company dated November 17, 2008,
incorporated by reference to Exhibit 10.3 to the November 2008
8-K.
|
|
10.15
|
Employment
Letter from the Company to Robert P. Murphy dated December 21, 2006,
incorporated by reference to Exhibit 10.9 to the 2006 Annual Report
(“2006 Form 10-K”).
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|
10.16
|
Amendment to
Employment Agreement between Robert P. Murphy and Company effective
January 1, 2009, incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K, filed by the registrant with the Securities and
Exchange Commission on December 12, 2008.
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|
10.17
|
Master
Agreement between the Company and Cal Dive International, Inc. dated
December 8, 2006, incorporated by reference to Exhibit 10.10 to
the 2006 Form 10-K.
|
|
10.18
|
Tax Agreement
between the Company and Cal Dive International, Inc. dated
December 14, 2006, incorporated by reference to Exhibit 10.11 to
the 2006 Form 10-K.
|
|
10.19
|
Registration
Rights Agreement dated as of December 21, 2007 by and among Helix
Energy Solutions Group, Inc., the Guarantors named therein and Banc of
America Securities LLC, as representative of the Initial Purchasers,
incorporated by reference to Exhibit 10.1 to December 2007
8-K.
|
|
10.20
|
Purchase
Agreement dated as of December 18, 2007 by and among Helix Energy
Solutions Group, Inc., the Guarantors named therein and Banc of America
Securities LLC, and the other Initial Purchasers named therein
incorporated by reference to Exhibit 10.2 to the December 2007
8-K.
|
|
10.21
|
Letter
Agreement by and between Helix Energy Solutions Group, Inc. and Martin R.
Ferron dated February 8, 2008 incorporated by reference to
Exhibit 10.1 to the Current Report on Form 8-K, filed by the
registrant with the Securities and Exchange Commission on February 8,
2008 (the “February 2008 8-K”).
|
|
10.22
|
Letter
Agreement by and between Helix Energy Solutions Group, Inc. and Alan Wade
Pursell dated June 25, 2008 incorporated by reference to Exhibit 10.1
to the Current Report on Form 8-K, filed by the registrant with the
Securities and Exchange Commission on June 30, 2008 (the “June 2008
8-K”).
|
|
10.23
|
Employment
Agreement between Anthony Tripodo and the Company dated June 25, 2008,
incorporated by reference to Exhibit 10.2 to the June 2008
8-K.
|
|
10.24
|
First
Amendment to Employment Agreement between Anthony Tripodo and the Company
dated November 17, 2008, incorporated by reference to Exhibit 10.5 to the
November 2008 8-K.
|
|
10.25
|
Consulting
Agreement by and between A. Wade Pursell and the Company dated July 4,
2008, incorporated by reference to Exhibit 10.1 to the registrants
Quarterly Report on Form 10-Q, filed by the registrant with the Securities
and Exchange Commission on August 1, 2008.
|
|
10.26
|
Employment
Agreement between Lloyd A. Hajdik and Company dated November 17, 2008,
incorporated by reference to Exhibit 10.4 to the November 2008
8-K.
|
|
10.27
|
Stock
Repurchase Agreement between Company and Cal Dive International, Inc.
dated January 23, 2009, incorporated by reference to Exhibit
10.1 to the Current Report on Form 8-K, filed by the registrant with the
Securities and Exchange Commission on January 28, 2009.
|
|
10.28
|
Stock
Repurchase Agreement between Company and Cal Dive International, Inc.,
dated May 29, 2009 incorporated by reference to Exhibit 10.1 to
the Current Report on Form 8-K, filed by the registrant with the
Securities and Exchange Commission on June 1,
2009.
|
|
14.1
|
Code of
Ethics for Chief Executive Officer and Senior Financial Officers,
incorporated by reference to Exhibit 14.1 to the Registrant’s Current
Report on Form 8-K, filed by Registrant with the Securities and Exchange
Commission on December 7, 2009.
|
|
21.1*
|
|
|
23.1*
|
|
|
23.2*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
99.1
*
|
|
*
|
Filed
herewith.
|
|
**
|
Furnished
herewith.
|