|
UNITED
STATES
|
|
SECURITIES
AND EXCHANGE COMMISSION
|
|
WASHINGTON,
D.C. 20549
|
Form
10-Q
|
[X]
|
Quarterly
report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
|
|
|
For
the quarterly period ended September 30, 2009
|
||
|
or
|
||
|
[ ]
|
Transition
report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
|
|
|
For
the transition period from__________
to__________
|
||
Commission File
Number 001-32936
HELIX ENERGY SOLUTIONS GROUP,
INC.
(Exact
name of registrant as specified in its charter)
|
Minnesota
(State
or other jurisdiction
of
incorporation or organization)
|
|
95–3409686
(I.R.S.
Employer
Identification
No.)
|
|
|
||
|
400
North Sam Houston Parkway East
Suite
400
Houston,
Texas
(Address
of principal executive offices)
|
77060
(Zip
Code)
|
(281)
618–0400
(Registrant's
telephone number, including area code)
NOT
APPLICABLE
(Former
name, former address and former fiscal year, if changed since last
report)
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.
|
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 whether the
registrant is a large accelerated filer, an accelerated filer, or a
non-accelerated filer. See definition of “accelerated filer and large
accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
|
Large
accelerated filer
|
[ √ ]
|
Accelerated
filer
|
[ ]
|
Non-accelerated
filer
|
[ ]
|
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).
|
Yes
|
[ ]
|
No
|
[ √ ]
|
As of October 28, 2009,
104,312,684 shares of common stock were
outstanding.
TABLE OF CONTENTS
PART
I. FINANCIAL INFORMATION
Item
1. Financial Statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
(in
thousands)
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(Unaudited)
|
||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash
equivalents
|
$
|
410,506
|
$
|
223,613
|
||||
|
Accounts
receivable —
Trade,
net of allowance for uncollectible accounts
of
$4,399 and $5,905, respectively
|
185,519
|
427,856
|
||||||
|
Unbilled
revenue
|
22,558
|
42,889
|
||||||
|
Costs
in excess of billing
|
16,624
|
74,361
|
||||||
|
Other current
assets
|
130,546
|
172,089
|
||||||
|
Current assets of
discontinued operations
|
—
|
19,215
|
||||||
|
Total
current assets
|
765,753
|
960,023
|
||||||
|
Property and equipment
|
4,239,307
|
4,742,051
|
||||||
|
Less — accumulated
depreciation
|
(1,382,975
|
)
|
(1,323,608
|
)
|
||||
|
2,856,332
|
3,418,443
|
|||||||
|
Other
assets:
|
||||||||
|
Equity
investments
|
191,475
|
196,660
|
||||||
|
Goodwill
|
78,220
|
366,218
|
||||||
|
Other assets,
net
|
79,310
|
125,722
|
||||||
|
$
|
3,971,090
|
$
|
5,067,066
|
|||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$
|
177,118
|
$
|
344,807
|
||||
|
Accrued
liabilities
|
198,876
|
231,679
|
||||||
|
Income taxes
payable
|
108,213
|
—
|
||||||
|
Current maturities
of long-term debt
|
13,135
|
93,540
|
||||||
|
Current
liabilities of discontinued operations
|
—
|
2,772
|
||||||
|
Total
current liabilities
|
497,342
|
672,798
|
||||||
|
Long-term debt
|
1,347,395
|
1,933,686
|
||||||
|
Deferred income taxes
|
456,728
|
615,504
|
||||||
|
Decommissioning
liabilities
|
177,924
|
194,665
|
||||||
|
Other long-term
liabilities
|
10,148
|
81,637
|
||||||
|
Total
liabilities
|
2,489,537
|
3,498,290
|
||||||
|
Convertible preferred
stock
|
6,000
|
55,000
|
||||||
|
Commitments and
contingencies
|
||||||||
|
Shareholders’
equity:
|
||||||||
|
Common
stock, no par, 240,000 shares authorized,
104,378
and 91,972 shares issued, respectively
|
905,455
|
806,905
|
||||||
|
Retained
earnings
|
575,504
|
417,940
|
||||||
|
Accumulated other
comprehensive loss
|
(26,931
|
)
|
(33,696
|
)
|
||||
|
Total
controlling interest shareholders’ equity
|
1,454,028
|
1,191,149
|
||||||
|
Noncontrolling
interests
|
21,525
|
322,627
|
||||||
|
Total
equity
|
1,475,553
|
1,513,776
|
||||||
|
$
|
3,971,090
|
$
|
5,067,066
|
|||||
The accompanying
notes are an integral part of these condensed consolidated financial
statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in
thousands, except per share amounts)
|
Three
Months Ended
|
||||||||
|
September
30,
|
||||||||
|
2009
|
2008
|
|||||||
|
Net revenues:
|
||||||||
|
Contracting
services
|
$
|
152,310
|
$
|
473,117
|
||||
|
Oil
and
gas
|
63,715
|
134,619
|
||||||
|
216,025
|
607,736
|
|||||||
|
Cost of
sales:
|
||||||||
|
Contracting
services
|
127,402
|
318,451
|
||||||
|
Oil
and
gas
|
86,006
|
90,205
|
||||||
|
213,408
|
408,656
|
|||||||
|
Gross
profit
|
2,617
|
199,080
|
||||||
|
Gain on oil
and gas derivative commodity contracts
|
4,598
|
2,705
|
||||||
|
Gain on sale
of assets,
net
|
—
|
(23
|
)
|
|||||
|
Selling and
administrative
expenses
|
(21,884
|
)
|
(48,539
|
)
|
||||
|
Income (loss)
from
operations
|
(14,669
|
)
|
153,223
|
|||||
|
Equity
in earnings of
investments
|
13,385
|
8,751
|
||||||
|
Gain
on sale of Cal Dive
common stock
|
17,901
|
—
|
||||||
|
Net
interest expense and
other
|
(10,306
|
)
|
(28,298
|
)
|
||||
|
Income before
income
taxes
|
6,311
|
133,676
|
||||||
|
Provision
for income
taxes
|
(4,468
|
)
|
(54,165
|
)
|
||||
|
Income from
continuing
operations
|
1,843
|
79,511
|
||||||
|
Income
(loss) from discontinued operations, net of tax
|
3,021
|
(93
|
)
|
|||||
|
Net income,
including noncontrolling interests
|
4,864
|
79,418
|
||||||
|
Net
income applicable to noncontrolling interests
|
(844
|
)
|
(19,240
|
)
|
||||
|
Net income
applicable to
Helix
|
4,020
|
60,178
|
||||||
|
Preferred
stock
dividends
|
(125
|
)
|
(881
|
)
|
||||
|
Net income
applicable to Helix common shareholders
|
$
|
3,895
|
$
|
59,297
|
||||
|
Basic
earnings per share of common stock:
|
||||||||
|
Continuing
operations
|
$
|
0.01
|
$
|
0.65
|
||||
|
Discontinued
operations
|
0.03
|
—
|
||||||
|
Net
income per common
share
|
$
|
0.04
|
$
|
0.65
|
||||
|
Diluted
earnings per share of common stock:
|
||||||||
|
Continuing
operations
|
$
|
0.01
|
$
|
0.63
|
||||
|
Discontinued
operations
|
0.03
|
—
|
||||||
|
Net
income per common
share
|
$
|
0.04
|
$
|
0.63
|
||||
|
Weighted
average common shares outstanding:
|
||||||||
|
Basic
|
101,282
|
90,725
|
||||||
|
Diluted
|
101,334
|
94,583
|
||||||
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
|
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in
thousands, except per share amounts)
|
Nine
Months Ended
|
||||||||
|
September
30,
|
||||||||
|
2009
|
2008
|
|||||||
|
Net revenues:
|
||||||||
|
Contracting
services
|
$
|
967,751
|
$
|
1,079,804
|
||||
|
Oil and gas
|
313,888
|
499,831
|
||||||
|
1,281,639
|
1,579,635
|
|||||||
|
Cost of
sales:
|
||||||||
|
Contracting
services
|
765,602
|
777,206
|
||||||
|
Oil and gas
|
216,454
|
295,688
|
||||||
|
982,056
|
1,072,894
|
|||||||
|
Gross
profit
|
299,583
|
506,741
|
||||||
|
Gain on oil
and gas derivative commodity contracts
|
83,328
|
2,705
|
||||||
|
Gain on sale of assets,
net
|
1,773
|
79,893
|
||||||
|
Selling and administrative
expenses
|
(102,609
|
)
|
(136,953
|
)
|
||||
|
Income from operations
|
282,075
|
452,386
|
||||||
|
Equity in earnings
of investments
|
27,152
|
25,722
|
||||||
|
Gain
on sale of Cal Dive common stock
|
77,343
|
—
|
||||||
|
Net interest
expense and other
|
(39,969
|
)
|
(76,914
|
)
|
||||
|
Income before income
taxes
|
346,601
|
401,194
|
||||||
|
Provision for
income taxes
|
(126,196
|
)
|
(151,638
|
)
|
||||
|
Income from continuing
operations
|
220,405
|
249,556
|
||||||
|
Income
from discontinued operations, net of tax
|
10,303
|
1,671
|
||||||
|
Net income,
including noncontrolling interests
|
230,708
|
251,227
|
||||||
|
Net
income applicable to noncontrolling interests
|
(19,017
|
)
|
(26,553
|
)
|
||||
|
Net income applicable to
Helix
|
211,691
|
224,674
|
||||||
|
Preferred stock
dividends
|
(688
|
)
|
(2,642
|
)
|
||||
|
Preferred
stock beneficial conversion charges
|
(53,439
|
)
|
—
|
|||||
|
Net income
applicable to Helix common shareholders
|
$
|
157,564
|
$
|
222,032
|
||||
|
Basic
earnings per share of common stock:
|
||||||||
|
Continuing
operations
|
$
|
1.49
|
$
|
2.40
|
||||
|
Discontinued
operations
|
0.10
|
0.02
|
||||||
|
Net income per
common share
|
$
|
1.59
|
$
|
2.42
|
||||
|
Diluted
earnings per share of common stock:
|
||||||||
|
Continuing
operations
|
$
|
1.38
|
$
|
2.32
|
||||
|
Discontinued
operations
|
0.10
|
0.02
|
||||||
|
Net income per
common share
|
$
|
1.48
|
$
|
2.34
|
||||
|
Weighted
average common shares outstanding:
|
||||||||
|
Basic
|
97,831
|
90,598
|
||||||
|
Diluted
|
105,868
|
95,096
|
||||||
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
|
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in
thousands)
|
Nine
Months Ended
|
||||||||
|
September
30,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash flows from operating activities:
|
||||||||
|
Net income,
including noncontrolling interests
|
$
|
230,708
|
$
|
251,227
|
||||
|
Adjustments
to reconcile net income including noncontrolling interests to net cash
provided by operating activities —
|
||||||||
|
Depreciation,
depletion and amortization
|
208,870
|
246,870
|
||||||
|
Asset
impairment charges and dry hole expense
|
64,610
|
24,156
|
||||||
|
Equity
in (earnings) losses of investments, net of distributions
|
(222
|
)
|
2,495
|
|||||
|
Amortization
of deferred financing
costs
|
4,095
|
4,163
|
||||||
|
Income
from discontinued
operations
|
(10,303
|
)
|
(1,671
|
)
|
||||
|
Stock
compensation
expense
|
9,435
|
17,933
|
||||||
|
Amortization
of debt
discount
|
5,878
|
5,508
|
||||||
|
Deferred
income
taxes
|
(53,012
|
)
|
54,925
|
|||||
|
Excess
tax benefit from stock-based compensation
|
2,036
|
(1,142
|
)
|
|||||
|
Gain
on sale of
assets
|
(1,773
|
)
|
(79,893
|
)
|
||||
|
Unrealized
(gain) loss on derivative contracts
|
(19,785
|
)
|
4,045
|
|||||
|
Gain
on sale of investment in Cal Dive common stock
|
(77,343
|
)
|
—
|
|||||
|
Changes
in operating assets and liabilities:
|
||||||||
|
Accounts
receivable,
net
|
7,215
|
(48,002
|
)
|
|||||
|
Other
current
assets
|
33,483
|
(4,777
|
)
|
|||||
|
Income
tax
payable
|
157,931
|
742
|
||||||
|
Accounts
payable and accrued liabilities
|
(46,213
|
)
|
(78,902
|
)
|
||||
|
Other
noncurrent,
net
|
(78,349
|
)
|
(60,221
|
)
|
||||
|
Cash
provided by operating
activities
|
437,261
|
337,456
|
||||||
|
Cash
provided by (used in) discontinued operations
|
(6,089
|
)
|
1,630
|
|||||
|
Net
cash provided by operating activities
|
431,172
|
339,086
|
||||||
|
Cash flows
from investing activities:
|
||||||||
|
Capital
expenditures
|
(306,152
|
)
|
(728,692
|
)
|
||||
|
Distributions
from equity investments,
net
|
4,774
|
4,636
|
||||||
|
Proceeds
from the sale of Cal Dive common stock
|
418,168
|
—
|
||||||
|
Reduction
in cash from deconsolidation of Cal Dive
|
(112,995
|
)
|
—
|
|||||
|
Proceeds
from sales of
properties
|
23,238
|
230,261
|
||||||
|
Other
|
(564
|
)
|
(1,261
|
)
|
||||
|
Cash
provided by (used in) investing activities
|
26,469
|
(495,056
|
)
|
|||||
|
Cash
provided by (used in) discontinued operations
|
20,872
|
(111
|
)
|
|||||
|
Net
cash provided by (used in) investing activities
|
47,341
|
(495,167
|
)
|
|||||
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in
thousands)
(Continued)
|
Nine
Months Ended
|
||||||||
|
September
30,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash flows
from financing activities:
|
||||||||
|
Repayment
of Helix Term
Notes
|
(3,245
|
)
|
(3,245
|
)
|
||||
|
Borrowings
on Helix
Revolver
|
—
|
847,000
|
||||||
|
Repayments
on Helix
Revolver
|
(349,500
|
)
|
(690,000
|
)
|
||||
|
Repayment
of MARAD
borrowings
|
(4,214
|
)
|
(4,014
|
)
|
||||
|
Borrowings
on CDI
Revolver
|
100,000
|
61,100
|
||||||
|
Repayments
on CDI
Revolver
|
—
|
(61,100
|
)
|
|||||
|
Repayments
on CDI Term
Notes
|
(20,000
|
)
|
(40,000
|
)
|
||||
|
Deferred
financing
costs
|
(50
|
)
|
(1,711
|
)
|
||||
|
Capital
lease
payments
|
—
|
(1,505
|
)
|
|||||
|
Preferred
stock dividends
paid
|
(625
|
)
|
(2,642
|
)
|
||||
|
Repurchase
of common
stock
|
(10,603
|
)
|
(3,912
|
)
|
||||
|
Excess
tax benefit from stock-based compensation
|
(2,036
|
)
|
1,142
|
|||||
|
Exercise
of stock options,
net
|
36
|
2,139
|
||||||
|
Net
cash provided by (used in) financing activities
|
(290,237
|
)
|
103,252
|
|||||
|
Effect of
exchange rate changes on cash and cash equivalents
|
(1,383
|
)
|
(965
|
)
|
||||
|
Net increase
(decrease) in cash and cash equivalents
|
186,893
|
(53,794
|
)
|
|||||
|
Cash and cash
equivalents:
|
||||||||
|
Balance,
beginning of
year
|
223,613
|
89,555
|
||||||
|
Balance,
end of
period
|
$
|
410,506
|
$
|
35,761
|
||||
The accompanying
notes are an integral part of these condensed consolidated financial
statements.
HELIX
ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 – Basis of Presentation
The accompanying
condensed consolidated financial statements include the accounts of Helix Energy
Solutions Group, Inc. and its majority-owned subsidiaries (collectively, "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. On June 10, 2009, our ownership in Cal Dive
International Inc. (“Cal Dive” or “CDI”) was reduced to less than
50%. Accordingly, we ceased consolidating CDI as of that date and we
accounted for our remaining approximate 26% ownership interest under the equity
method of accounting through September 23, 2009, at which time we sold
substantially all of our remaining ownership interest in Cal Dive (Notes 3 and
4). All material intercompany accounts and transactions have been
eliminated. These condensed consolidated financial statements are unaudited,
have been prepared pursuant to instructions for the Quarterly Report on Form
10-Q required to be filed with the Securities and Exchange Commission (“SEC”),
and do not include all information and footnotes normally included in annual
financial statements prepared in accordance with U.S. generally accepted
accounting principles.
The accompanying condensed
consolidated financial statements have been prepared in conformity with U.S.
generally accepted accounting principles and are consistent in all material
respects with those applied in our Annual Report on Form 10-K for the year ended
December 31, 2008 (“2008 Form 10-K”) and those applied in our Current Report on
Form 8-K as filed with the Securities and Exchange Commission (“SEC”) on June
16, 2009 (“June 2009 Form 8-K”), which among other things, reflected the effect
our adoption on January 1, 2009 of certain accounting standards that
require retrospective application had on our year-end 2008 financial
statements. The preparation of these financial statements requires us
to make estimates and judgments that affect the amounts reported in the
financial statements and the related disclosures. Actual results may
differ from our estimates. Management has reflected all adjustments
(which were normal recurring adjustments unless otherwise disclosed herein) that
it believes are necessary for a fair presentation of the condensed consolidated
balance sheets, results of operations, and cash flows, as
applicable. Operating results for the three month and nine month
periods ended September 30, 2009 are not necessarily indicative of the results
that may be expected for the year ending December 31, 2009. Our
balance sheet as of December 31, 2008 included herein has been derived from the
audited balance sheet as of December 31, 2008 included in our June 2009 Form
8-K. These condensed consolidated financial statements should be read in
conjunction with the annual consolidated financial statements and notes thereto
included in our June 2009 Form 8-K.
Certain reclassifications were made
to previously reported amounts in the condensed consolidated financial
statements and notes thereto to make them consistent with the current
presentation format, including the adoption of certain recent accounting
pronouncements that require retrospective application (Note 3) and the
presentation of a former business unit as discontinued operations (Note
2). We have conducted our subsequent events review through October
30, 2009, the date our financial statements were filed with the
SEC.
Note
2 – Company Overview
We
are an international offshore energy company that provides development solutions
and other key life of field contracting services to the energy market as well as
to our own oil and gas business unit. Our Contracting Services
segment utilizes our vessels, offshore equipment and proprietary technologies to
deliver services that may reduce finding and development costs and encompass 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 Middle East
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 four disciplines: construction,
well operations, drilling, and production facilities. We have disaggregated our
contracting services operations into three reportable segments in accordance
with Financial Accounting Standards Board (“FASB”) Codification Topic No. 280
Segment
Reporting: Contracting Services, Production Facilities and Shelf
Contracting. Our Contracting Services business includes subsea
construction, well operations, robotics and drilling. Our Production
Facilities business includes our investments in Deepwater Gateway, L.L.C.
(“Deepwater Gateway”), Independence Hub, LLC (“Independence Hub”) and Kommandor
LLC (“Kommandor”). In April 2009, Kommandor LLC completed the initial
conversion of the Helix
Producer I (“HP I”) vessel. The vessel is currently undergoing
further modification to install top side production
facilities. The completed vessel is expected to be ready for
service in the first half of 2010, and is currently scheduled to be deployed to
our deepwater Phoenix oil and gas field that is being developed in parallel with
the planned delivery of the HP I. We have sold substantially all our
remaining ownership interest in CDI (Note 4). CDI’s operations
represented our former Shelf Contracting business, which we deconsolidated on
June 10, 2009 (Notes 3 and 4).
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 to our
contracting services. Since 1992, 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 condensed consolidated
financial statements. HEL and Helix RDS were previously components of
our Contracting Services segment. We recognized an $8.8 million
gain on the sale of HEL. The operating results of HEL and Helix
RDS were immaterial to our results for all periods
presented.
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 (see Note 2 of our 2008 Form 10-K).
Our stock price decreased further in the first 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 through September 30,
2009. At September 30, 2009 our remaining goodwill totaled $78.2
million, all of which is attributable to our Contracting Services
segment.
Our Contracting
Services segment may also 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. We forecast weaker demand for
our contracting services for the remainder of 2009. 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 2009 when we entered into
commodity hedges during 2008. These hedge contracts enable us to
minimize our near-term cash flow risks related to declining commodity
prices. Similarly, throughout the nine months ended September 30,
2009, we have entered into a number of financial derivative contracts to hedge a
substantial portion of our forecasted production of both oil and natural gas for
2010. See Note 19 for additional information regarding our oil and
gas hedge contracts.
Note
3 – Recent Accounting Pronouncements
We
have adopted the fair value accounting standards as contained in FASB
Codification Topic No. 280 “Fair
Value Measurements and Disclosures.” These standards
among other things, define fair value, establish a consistent framework for
measuring fair value and expand disclosure for each major asset and liability
category measured at fair value on either a recurring or nonrecurring
basis. The FASB has clarified 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. The following is the three-tier fair value
hierarchy established by the FASB, 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 in 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. 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 September 30, 2009 (in
thousands):
|
Level
1
|
Level
2
|
Level
3
|
Total
|
Valuation
Technique
|
|||||||||||||
|
Assets:
|
|||||||||||||||||
|
Oil and gas derivatives
|
$ | – | $ | 16,711 | – | $ | 16,711 |
(c)
|
|||||||||
|
Foreign
currency forwards
|
– | 2,077 | – | 2,077 |
(c)
|
||||||||||||
|
Investment
in Cal Dive (Note 4)
|
4,945 | – | – | 4,945 |
(a)
|
||||||||||||
|
Liabilities:
|
|||||||||||||||||
|
Gas
swaps and collars
|
– | 13,890 | – | 13,890 |
(c)
|
||||||||||||
|
Interest
rate
swaps
|
– | 2,388 | – | 2,388 |
(c)
|
||||||||||||
|
Total
|
4,945 | $ | 2,510 | – | $ | 7,455 | |||||||||||
In
December 2007, the FASB issued Statement No. 160, Noncontrolling
Interests in Consolidated
Financial Statements — an amendment of ARB 51. These standards are
now included in FASB Codification Topic No. 810 Consolidation. 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.
8
We
adopted these standards on January 1, 2009, which are 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 4
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
FASB Codification 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 19
below for the required disclosures for our derivative
instruments.
Effective January 1, 2009, we
adopted accounting standards as required in FASB Codification 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).
The following table sets forth the
effect of retrospective application of the adoption of new accounting standards
and the effect on earnings per share (Note 14) and discontinued operations on
certain previously reported line items in our accompanying condensed
consolidated statements of operations (in thousands, except per share
data):
|
Three Months
Ended
September 30,
2008
|
||||||||
|
Originally
Reported
|
As
Adjusted
|
|||||||
|
Net interest
expense and
other
|
$ | 23,464 | $ | 28,298 | ||||
|
Provision for
Income
taxes
|
54,816 | 54,165 | ||||||
|
Net
income from continuing
operations
|
80,708 | 79,511 | ||||||
|
Earnings per
common share from continuing operations – Basic
|
$ | 0.67 | $ | 0.65 | ||||
|
Earnings per
common share from continuing operations – Diluted
|
0.65 | 0.63 | ||||||
|
Nine Months
Ended
September 30,
2008
|
||||||||
|
Originally
Reported
|
As
Adjusted
|
|||||||
|
Net interest
expense and
other
|
$ | 68,178 | $ | 76,914 | ||||
|
Provision for
Income
taxes
|
154,373 | 151,638 | ||||||
|
Net
income from continuing
operations
|
255,019 | 249,556 | ||||||
|
Earnings per
common share from continuing operations - Basic
|
$ | 2.49 | $ | 2.42 | ||||
|
Earnings per
common share from continuing operations – Diluted
|
2.40 | 2.34 | ||||||
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,
FASB Codification 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.
Note
4 – Reduction in Ownership of Cal Dive
At December 31, 2008, we owned
approximately 57.2% of Cal Dive. During 2009, as previously
noted in Notes 1, 2 and 3, we engaged in a number of transactions
that ultimately resulted in our disposal of substantially all of our remaining
ownership in Cal Dive.
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 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 condensed 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 FASB
Codification 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 condensed consolidated
balance sheet at September 30, 2009 (Note 3). We intend to sell our
remaining shares of Cal Dive common stock over the near term as market
conditions warrant. The value of our remaining investment in Cal Dive
decreased by $0.1 million from the closing of the Second Offering to September
30, 2009.
Proceeds from our
Cal Dive stock sale transaction have been and will continue to be used for
general corporate purposes.
Note
5 – 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 and some of these
third party facilities remain out of service as of October 30,
2009. 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):
|
Third
Quarter
2009
|
Nine
Months Ended
September
30,
2009
|
Since
Inception in September 2008
|
||||||||||
|
Oil and
gas:
|
||||||||||||
|
Hurricane
repair
costs
|
$ | 5,060 | $ | 25,223 | $ | 47,774 | ||||||
|
ARO
liability adjustments
|
- | 43,812 | 48,065 | |||||||||
|
Hurricane-related
impairments
|
- | 7,699 | 37,585 | |||||||||
|
Insurance
recoveries
|
- | (100,874 | ) | (118,415 | ) | |||||||
|
Net
(reimbursements) costs
|
$ | 5,060 | $ | (24,140 | ) | $ | 15,009 | |||||
|
Contracting
services:
|
||||||||||||
|
Hurricane
repair
costs
|
$ | - | $ | 776 | $ | 6,026 | ||||||
|
Insurance
recoveries
|
(159 | ) | (2,885 | ) | (5,022 | ) | ||||||
|
Net
(reimbursements) costs
|
$ | (159 | ) | (2,109 | ) | 1,004 | ||||||
|
Shelf
Contracting:
|
||||||||||||
|
Hurricane
repair
costs
|
$ | 3 | $ | 613 | $ | 4,550 | ||||||
|
Insurance
recoveries
|
(238 | ) | (2,849 | ) | (5,183 | ) | ||||||
|
Net
(reimbursements) costs
|
$ | (235 | ) | $ | (2,236 | ) | (633 | ) | ||||
|
Totals:
|
||||||||||||
|
Hurricane
repair
costs
|
$ | 5,063 | $ | 26,612 | $ | 58,350 | ||||||
|
ARO
liability adjustments
|
- | 43,812 | 48,065 | |||||||||
|
Hurricane-related
impairments
|
- | 7,699 | 37,585 | |||||||||
|
Insurance
recoveries
|
(397 | ) | (106,608 | ) | (128,620 | ) | ||||||
|
Net
(reimbursements) costs
|
$ | 4,666 | $ | (28,485 | ) | $ | 15,380 | |||||
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 substantially all of the remaining $2.7 million of premium will be
charged to expense in the fourth quarter of 2009. The
expense associated with the Catastrophic Bond premium is recorded as a component
of lease operating expense for our oil and gas operations.
Note
6 – Details of Certain Accounts (in thousands)
Other Current Assets consisted of
the following as of September 30, 2009 and December 31,
2008:
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Other receivables
|
$ | 10,486 | $ | 22,977 | ||||
|
Prepaid insurance
|
16,335 | 18,327 | ||||||
|
Other prepaids
|
12,779 | 23,956 | ||||||
|
Inventory
|
26,856 | 32,195 | ||||||
|
Current deferred tax
assets
|
25,701 | 3,978 | ||||||
|
Hedging assets
|
17,830 | 26,800 | ||||||
|
Income tax receivable
|
— | 23,485 | ||||||
|
Gas imbalance
|
7,603 | 7,550 | ||||||
|
Investments available for
sale
|
4,945 | — | ||||||
|
Other
|
8,011 | 12,821 | ||||||
| $ | 130,546 | $ | 172,089 | |||||
Other Assets, net, consisted of the
following as of September 30, 2009 and December 31, 2008:
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Restricted cash
|
$ | 35,416 | $ | 35,402 | ||||
|
Deferred drydock expenses,
net
|
13,221 | 38,620 | ||||||
|
Deferred financing costs
|
25,641 | 33,431 | ||||||
|
Intangible assets with
definite lives, net
|
842 | 7,600 | ||||||
|
Other
|
4,190 | 10,669 | ||||||
| $ | 79,310 | $ | 125,722 | |||||
Accrued Liabilities consisted of the
following as of September 30, 2009 and December 31, 2008:
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Accrued payroll and related
benefits
|
$ | 36,146 | $ | 46,224 | ||||
|
Royalties payable
|
4,153 | 10,265 | ||||||
|
Current decommissioning
liability
|
73,566 | 31,116 | ||||||
|
Unearned revenue
|
7,925 | 9,353 | ||||||
|
Billings in excess of
costs
|
1,307 | 13,256 | ||||||
|
Accrued interest
|
16,942 | 34,299 | ||||||
|
Deposit
|
25,542 | 25,542 | ||||||
|
Hedge liability
|
9,218 | 7,687 | ||||||
|
Other
|
24,077 | 53,937 | ||||||
| $ | 198,876 | $ | 231,679 | |||||
Note
7 – 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 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 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 conversion 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
September 30, 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.
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 September 30, 2009) will be included in our diluted
shares outstanding amount. However, our earnings from continuing
operations for the three month period ended September 30, 2009 resulted in the
assumed conversion of the convertible preferred stock to be anti-dilutive,
meaning its assumed conversion would have increased our diluted earnings per
share calculation (Note 14).
Note
8 – 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 in which the drilling is determined to be
unsuccessful.
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.
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. 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 United States Supreme Court
decision to deny the plaintiff’s writ of certiorari in October
2009.
Property
Sales
In the first
quarter of 2009, we sold our interest in East Cameron Block 316 for gross
proceeds of approximately $18 million. We recorded an approximate
$0.7 million gain from the sale of East Cameron Block 316 which was partially
offset by the loss on the sale of the remaining 10% of our interest in the Bass
Lite field at Atwater Valley Block 426 in January 2009. In the second
quarter we sold three fields for gross proceeds of $0.8 million and resulting in
an aggregate gain of $1.2 million, including transfer of the respective field’s
asset retirement obligations.
In March and April
2008, we sold an aggregate 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 (of which $30.5 million was recognized in second
quarter 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, Oklahoma,
New Mexico and Wyoming (“Onshore Properties”) to an unrelated
investor. We sold these Onshore Properties for cash proceeds of $47.2
million and recorded a related loss of $11.9 million in the second quarter of
2008. Included in the cost basis of the Onshore Properties was an
$8.1 million allocation of goodwill from our Oil and Gas
segment.
Exploration
and Other
As
of September 30, 2009, we capitalized approximately $2.9 million of costs
associated with ongoing exploration and/or appraisal activities. Such
capitalized costs may be charged against earnings in future periods if
management determines that commercial quantities of hydrocarbons have not been
discovered or that future appraisal drilling or development activities are not
likely to occur.
Further, the
following table details the components of exploration expense for the three and
nine months ended September 30, 2009 and 2008 (in thousands):
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
|
September
30,
|
September
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Delay rental
and geological and geophysical costs
|
$
|
755
|
$
|
1,375
|
$
|
2,288
|
$
|
4,753
|
||||||||
|
Dry hole expense
|
149
|
270
|
575
|
254
|
||||||||||||
|
Total
exploration expense
|
$
|
904
|
$
|
1,645
|
$
|
2,863
|
$
|
5,007
|
||||||||
In 2009, we farmed-out our 100%
leasehold interests in Green Canyon Block 490 located in the deepwater of the
Gulf of Mexico. Our farmout 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
In
the second quarter of 2009, we recorded an aggregate of approximately $63.1
million of impairment charges, which are reflected as a reduction to our cost of
sales. These charges primarily reflect the approximate $51.5 million
of impairment-related charges recorded to properties that were severely damaged
by Hurricane Ike (Note 5). 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. We recorded an aggregate $1.5 million of additional impairment
charges associated with five fields following a comprehensive impairment
analysis at September 30, 2009. Prior to the impairments charges
discussed above, the aggregate net book value of the affected fields was $68.9
million. The impairment charges reduced the fields to their
then aggregate net fair value of $4.2 million. The
substantial majority of the impairments were associated with fields to which we
had to increase our reclamation obligation estimates. We have
concluded that this valuation is classified with level three of the valuation
hierarchy (Note 3).
For the nine months
ended September 30, 2008 we recorded impairment charges totaling
$23.9 million as a component of oil and gas cost of sales in the
accompanying condensed statement of operations. These impairments
primarily reflected the $14.6 million of costs associated with the unsuccessful
development well on Devil’s Island (Garden Banks Block 344) and $6.7 million
related to our Tiger deepwater field that was damaged by Hurricane Ike.
The following table describes the
changes in our asset retirement obligations (both long term and current) since
December 31, 2008 (in thousands):
|
Asset
retirement obligation at December 31, 2008
|
$
|
225,781
|
||
|
Liability
transferred to third party during the period
|
(3,506
|
)
|
||
|
Liability
settled during the
period
|
(45,848
|
)
|
||
|
Revision in
estimated cash
flows
|
63,462
|
a
|
||
|
Accretion
expense (included in depreciation and amortization)
|
11,601
|
|||
|
Asset
retirement obligations at December
31,
|
$
|
251,490
|
|
a.
|
Increase in
estimates primary associated with properties damaged during Hurricane
Ike
(Note 5).
|
Note
9 – Statement of Cash Flow Information
We define cash and cash equivalents
as cash and all highly liquid financial instruments with original maturities of
less than three months. As of September 30, 2009 and December 31,
2008, our restricted cash totaled $35.4 million and is included in other assets,
net. All of our restricted cash relates to funds required to be
escrowed to cover the future decommissioning liabilities associated with the
South Marsh Island Block 130, which we acquired in 2002. We have
fully satisfied the escrow requirements under this agreement and may use the
restricted cash for future decommissioning of the related
field.
The following table provides
supplemental cash flow information for the nine months ended September 30, 2009
and 2008 (in thousands):
|
Nine
Months Ended
|
||||||||
|
September
30,
|
||||||||
|
2009
|
2008
|
|||||||
|
Interest
paid, net of capitalized interest
|
$
|
51,696
|
$
|
46,649
|
||||
|
Income taxes paid
|
$
|
57,412
|
$
|
97,059
|
||||
Non-cash investing
activities for the nine months ended September 30, 2009 included $63.6 million
of accruals for capital expenditures. Non-cash investing activities
for the nine months ended September 30, 2008 totaled $28.6
million. The accruals have been reflected in the condensed
consolidated balance sheet as an increase in property and equipment and accounts
payable.
Note
10 – Equity Investments
As
of September 30, 2009, we have the following material investments, both of which
are included within our Production Facilities segment and are accounted for
under the equity method of accounting:
|
·
|
Deepwater
Gateway, L.L.C. In June 2002, we, along with Enterprise
Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, L.L.C.
(“Deepwater Gateway”) (each with a 50% interest) to design, construct,
install, own and operate a tension leg platform (“TLP”) production hub
primarily for Anadarko Petroleum Corporation's Marco
Polo field in the Deepwater Gulf of Mexico. Our investment in
Deepwater Gateway totaled $104.3 million and $106.3 million as of
September 30, 2009 and December 31, 2008, respectively (including
capitalized interest of $1.5 million and $1.6 million at September 30,
2009 and December 31, 2008, respectively). Our equity in the
earnings of Deepwater Gateway totaled $1.0 million and $2.5 million for
the three month and nine month periods ended September 30, 2009 compared
with $4.1 million and $14.4 million during the respective prior year
periods. Distributions from Deepwater Gateway, net to our
interest, totaled $4.5 million for the nine months ended September 30,
2009.
|
|
·
|
Independence
Hub, LLC. In December 2004, we acquired a 20% interest
in Independence Hub, LLC (“Independence”), an affiliate of
Enterprise. Independence owns the "Independence Hub" platform
located in Mississippi Canyon Block 920 in a water depth of 8,000
feet. First production began in July 2007. Our
investment in Independence was $87.2 million and $90.2 million as of
September 30, 2009 and December 31, 2008, respectively (including
capitalized interest of $5.6 million and $5.9 million at September 30,
2009 and December 31, 2008, respectively). Our equity in the
earnings of Independence Hub totaled $5.3 million and $17.2 million for
the three month and nine month periods ended September 30, 2009 compared
with $4.8 million and $13.9 million during the respective prior
year periods. Distributions from Independence, net to our
interest, totaled $20.0 million for the nine months ended September 30,
2009.
|
Also included
within our Production Facilities segment is our investment in Kommandor LLC, the
results of which we consolidate in our financial statements.
As
disclosed in Note 4, in June 2009 we sold shares of Cal Dive common stock that
reduced our ownership in Cal Dive to less than 50%. Accordingly we
deconsolidated Cal Dive from our financial statements effective June 11,
2009. We accounted for our remaining approximate 26% ownership
interest in Cal Dive using the equity method until September 23, 2009, at which
time we sold substantially all our remaining ownership interest in Cal
Dive. The fair value of our remaining investment in
Cal Dive was approximately $4.9 million at September 30, 2009 (Note
3).
Note
11 – Long-Term Debt
Scheduled
maturities of long-term debt and capital lease obligations outstanding as of
September 30, 2009 were as follows (in thousands):
|
Helix
Term Loan
|
Helix
Revolving Loans
|
Senior
Unsecured Notes
|
Convertible
Senior Notes
|
MARAD
Debt
|
Other(1)
|
Total
|
|||||||||||||||||
|
Less than one year
|
$
|
4,326
|
$
|
─
|
$
|
─
|
$
|
─
|
$
|
4,424
|
$
|
4,385
|
$
|
13,135
|
|||||||||
|
One to two years
|
4,326
|
─
|
─
|
─
|
4,645
|
─
|
8,971
|
||||||||||||||||
|
Two to three years
|
4,326
|
─
|
─
|
─
|
4,877
|
─
|
9,203
|
||||||||||||||||
|
Three to four years
|
402,870
|
─
|
─
|
─
|
5,120
|
─
|
407,990
|
||||||||||||||||
|
Four to five years
|
─
|
─
|
─
|
─
|
5,376
|
─
|
5,376
|
||||||||||||||||
|
Over five years
|
─
|
─
|
550,000
|
300,000
|
94,793
|
─
|
944,793
|
||||||||||||||||
|
Total debt
|
415,848
|
─
|
550,000
|
300,000
|
119,235
|
4,385
|
1,389,468
|
||||||||||||||||
|
Current maturities
|
(4,326
|
)
|
─
|
─
|
─
|
(4,424
|
)
|
(4,385
|
)
|
(13,135
|
)
|
||||||||||||
|
Long-term
debt, less
current
maturities
|
$
|
411,522
|
$
|
─
|
$
|
550,000
|
$
|
300,000
|
$
|
114,811
|
$
|
─
|
$
|
1,376,333
|
|||||||||
|
Unamortized debt discount
(2)
|
─
|
─
|
─
|
(28,938
|
)
|
─
|
─
|
(28,938
|
)
|
||||||||||||||
|
Long-term debt
|
$
|
411,522
|
$
|
─
|
$
|
550,000
|
$
|
271,062
|
$
|
114,811
|
$
|
─
|
$
|
1,347,395
|
|||||||||
|
Fair Value (3),
(4), (5)
|
$
|
399,734
|
$
|
─
|
$
|
552,750
|
$
|
265,725
|
$
|
123,325
|
$
|
4,385
|
$
|
1,345,919
|
|||||||||
|
(1)
|
Reflects loan
provided by Kommandor RØMØ to Kommandor
LLC.
|
|
(2)
|
Reflects debt
discount resulting from adoption of 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.
|
|
(3)
|
The fair
value of the term loan, senior unsecured notes and convertible notes were
based on quoted market prices as of September 30, 2009 using level 1
inputs as defined in FASB Codification Topic No 280 using the market
approach (Note 3).
|
|
(4)
|
The fair
value of the MARAD debt was determined using 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 with similar terms. The fair value of the MARAD
debt was estimated using level 2 inputs using the cost approach (Note
3).
|
|
(5)
|
The loan
notes representing other in the table approximate fair
value.
|
We had unsecured letters of credit
outstanding at September 30, 2009 totaling approximately $49.7 million. These
letters of credit primarily guarantee various contract bids, contractual
performance, insurance activities and shipyard commitments. The
following table details our interest expense and capitalized interest for the
three and nine months ended September 30, 2009 and 2008 (in
thousands):
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
|
September
30,
|
September
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Interest expense
|
$
|
23,582
|
$
|
32,453
|
$
|
81,094
|
$
|
100,877
|
||||||||
|
Interest income
|
(282
|
)
|
(593
|
)
|
(694
|
)
|
(2,149
|
)
|
||||||||
|
Capitalized interest
|
(16,050
|
)
|
(10,045
|
)
|
(35,540
|
)
|
(30,618
|
)
|
||||||||
|
Interest
expense, net
|
$
|
7,250
|
$
|
21,815
|
$
|
44,860
|
$
|
68,110
|
||||||||
Included below is a summary of
certain components of our indebtedness. At September 30, 2009 and
December 31, 2008, we were in compliance with all debt covenants. For
additional information regarding our debt see Note 11 of our 2008 Form
10-K.
Senior
Unsecured Notes
In
December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due January
15, 2016 (“Senior Unsecured Notes”). Interest on the Senior Unsecured
Notes is payable semiannually in arrears on each January 15 and July 15,
commencing July 15, 2008. The Senior Unsecured Notes are fully and
unconditionally guaranteed by substantially all of our existing restricted
domestic subsidiaries, except for Cal Dive I-Title XI, Inc. In
addition, any future restricted domestic subsidiaries that guarantee any of our
indebtedness and/or our restricted subsidiaries’ indebtedness are required to
guarantee the Senior Unsecured Notes. Cal Dive I -Title XI,
Inc. and our foreign subsidiaries are not guarantors. CDI and its
subsidiaries were not guarantors of the Senior Unsecured Notes prior to
deconsolidation of CDI in June 2009 (Note 4). We used the proceeds
from the Senior Unsecured Notes to repay outstanding indebtedness under our
senior secured credit facilities (see below).
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
acquisition (see Note 4 of our 2008 Form 10-K). Total borrowing
capacity under the Revolving Credit Facility at September 30, 2009 totaled $420
million. The full amount of the Revolving Credit Facility may be used for
issuances of letters of credit. At September 30, 2009 we had no
amounts drawn on the Revolving Credit Facility and our availability under the
Facility totaled $370.3 million net of $49.7 million of unsecured letters of
credit issued.
The Term Loan
currently bears interest either at the one-, three- or six-month LIBOR at our
current election plus a 2.00% margin. Our average interest rate on
the Term Loan for the nine months ended September 30, 2009 and 2008 was
approximately 2.9% and 5.4%, respectively, including the effects of our interest
rate swaps (see below). 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 September 30, 2009.
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 existing 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 existing term loans 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.
|
Simultaneously with
entering into the amendment, we completed an increase in the
revolving line of credit from $420 million to $435 million
(decreasing to $407 million from July 1, 2011 through November 30, 2012)
utilizing the accordion feature included in the Credit Agreement through an
increase in the commitment from an existing lender.
Convertible
Senior Notes
In
March 2005, we issued $300 million of our 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.
The Convertible
Senior Notes can be converted prior to the stated maturity (March 2025) under
certain triggering events specified in the indenture governing the Convertible
Senior Notes. To the extent we do not have long-term financing
secured to cover the conversion, the Convertible Senior Notes would be
classified as a current liability in the accompanying balance
sheet. No conversion triggers were met during the nine month period
ended September 30, 2009. The first dates for early redemption of the
Convertible Senior Notes are in December 2012, with the holders of the
Convertible Senior Notes being able to put them to us on December 15, 2012 and
our being able to call the Convertible Senior Notes at any time after December
20, 2012 (see Note 11 of our 2008 Form 10-K). As a result of
adopting FSP APB 14-1 (Note 3), the effective interest is 6.6%.
Approximately 0.6
million shares underlying the Convertible Senior Notes were included
in the calculation of diluted earnings per share for the nine month period ended
September 30, 2008 because our average share price for the period was above the
conversion price of approximately $32.14 per share. Our average share
price was below the $32.14 per share conversion price for the three month period
ended September 30, 2008 and the three and nine month periods ended September
30, 2009. As a result of our share price being lower than the $32.14
per share conversion price for these periods there are no shares included in our
diluted earnings per share calculation associated with the assumed conversion of
our Convertible Senior Notes. In the event our average share price
exceeds the conversion price, there would be a premium, payable in shares of
common stock, in addition to the principal amount, which is paid in cash, and
such shares would be issued on conversion. The Convertible Senior
Notes are convertible into a maximum 13,303,770 shares of our common
stock.
MARAD
Debt
This U.S. government guaranteed
financing ("MARAD Debt") is pursuant to Title XI of the Merchant Marine Act of
1936 which is administered by the Maritime Administration and was used to
finance the construction of the Q4000.
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 Senior
Unsecured Notes, amended Senior Credit Facilities, Convertible Senior Notes and
the MARAD Debt agreements, we are required to comply with certain covenants and
restrictions, including the maintenance of minimum net worth, working capital
and debt-to-equity requirements. As of
September 30, 2009, we were in
compliance with these covenants and restrictions. The Senior
Unsecured Notes and Senior Credit Facilities contain provisions that limit our
ability to incur certain types of additional
indebtedness.
Other
Deferred financing costs of $25.6
million and $33.4 million are included in other assets, net as of September 30,
2009 and December 31, 2008, respectively, and are being amortized over the life
of the respective loan agreements.
Note
12 – Income Taxes
The effective tax
rate for the three month and nine month periods ended September 30, 2009 was
70.8% and 36.4%, respectively, compared with 40.5% and 37.8% for the three month
and nine month periods ended September 30, 2008. The effective tax rate
for the three months ended September 30, 2009 increased as a result of decreased
profitability and the reduced benefit derived from the Internal
Revenue Code §199 manufacturing deduction as it primarily related to oil and gas
production. The decrease in the effective rate for the nine month
period ended September 30, 2009 resulted from the deconsolidation of
Cal Dive. This benefit was partially offset by reduced Internal
Revenue Code §199 manufacturing deductions as it primarily related to oil and
gas production.
We
believe our recorded assets and liabilities are reasonable; however, tax laws
and regulations are subject to interpretation and tax litigation is inherently
uncertain; therefore our assessments can involve a series of complex judgments
about future events and rely heavily on estimates and assumptions.
Note
13 – Comprehensive Income (Loss)
The components of total
comprehensive income (loss) for the three and nine month periods ended September
30, 2009 and 2008 were as follows (in thousands):
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
|
September
30,
|
September
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Net income,
including noncontrolling interests
|
$
|
4,864
|
$
|
79,418
|
$
|
230,708
|
$
|
251,227
|
||||||||
|
Other
comprehensive income (loss), net of tax
|
||||||||||||||||
|
Foreign
currency translation gain
|
(3,343
|
)
|
(26,322
|
)
|
23,689
|
(23,929
|
)
|
|||||||||
|
Unrealized
loss on hedges, net
|
(2,883
|
)
|
14,073
|
(16,221
|
)
|
7,769
|
||||||||||
|
Unrealized
loss on investment available for sale
|
(130
|
)
|
─
|
(130
|
)
|
─
|
||||||||||
|
Total other accumulated
comprehensive income (loss)
|
(6,356
|
)
|
(12,249
|
)
|
7,338
|
(16,160
|
)
|
|||||||||
|
Less: Other
accumulated comprehensive loss applicable to noncontrolling
interest
|
(844
|
)
|
(19,347
|
)
|
(19,590
|
)
|
(26,811
|
)
|
||||||||
|
Total other
accumulated comprehensive loss applicable to Helix
|
|
(7,200
|
)
|
|
(31,596
|
)
|
|
(12,252
|
)
|
(42,971
|
)
|
|||||
| Total other comprehensive income (loss) applicable to Helix | $ | (2,336 | ) | $ | 47,882 | $ | 218,456 | $ | 208,256 | |||||||
The components of accumulated other
comprehensive loss was as follows (in thousands):
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Cumulative
foreign currency translation adjustment
|
$
|
(19,278
|
)
|
$
|
(42,874
|
)
|
||
|
Unrealized gain (loss) on
hedges, net
|
(7,523
|
)
|
9,178
|
|||||
|
Unrealized loss on investment
available for sale
|
(130
|
)
|
─
|
|||||
|
Accumulated
other comprehensive loss
|
$
|
(26,931
|
)
|
$
|
(33,696
|
)
|
||
Note
14 – Earnings Per Share
On January 1, 2009, we adopted 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
FSP 03-06-1, 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. Under FSP 03-06-1, we are required to compute EPS amounts
under the two class method. We have revised the prior period EPS
amounts to reflect the current year adoption of FSP 03-06-1 (see table
below).
Basic earnings per
share ("EPS") is computed by dividing the net income available to common
shareholders by the weighted average shares of outstanding common
stock. The calculation of diluted EPS is similar to basic EPS, except
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 EPS
amounts for the three month and nine month periods ended September 30, 2009 and
2008 are as follows (in thousands):
|
Three
Months Ended
|
Three
Months Ended
|
|||||||||||||||
|
September
30, 2009
|
September
30, 2008
|
|||||||||||||||
|
Income
|
Shares
|
Income
|
Shares
|
|||||||||||||
|
Basic:
|
||||||||||||||||
|
Net income
applicable to common shareholders
|
$
|
3,895
|
$
|
59,297
|
||||||||||||
|
Less:
Undistributed net income allocable to participating
securities
|
(53
|
)
|
(724
|
)
|
||||||||||||
|
Undistributed
net income applicable to common shareholders
|
3,842
|
58,573
|
||||||||||||||
|
(Income) loss
from discontinued operations
|
(3,021
|
)
|
93
|
|||||||||||||
|
Add:
Undistributed net income from discontinued operations allocable to
participating securities
|
41
|
(1
|
)
|
|||||||||||||
|
Income per
common share – continuing operations
|
$
|
862
|
101,282
|
$
|
58,665
|
90,725
|
||||||||||
|
Three
Months Ended
September
30, 2009
|
Three
Months Ended
September
30, 2008
|
|||||||||||||||
|
Income
|
Shares
|
Income
|
Shares
|
|||||||||||||
|
Diluted:
|
||||||||||||||||
|
Net income
per common share –
continuing
operations –
Basic
|
$
|
862
|
101,282
|
$
|
58,665
|
90,725
|
||||||||||
|
Effect of
dilutive securities:
|
||||||||||||||||
|
Stock
options
|
─
|
52
|
─
|
227
|
||||||||||||
|
Undistributed
earnings reallocated to participating securities
|
─
|
─
|
29
|
─
|
||||||||||||
|
Convertible
Senior Notes
|
─
|
─
|
─
|
─
|
||||||||||||
|
Convertible preferred stock
(a)
|
─
|
─
|
881
|
3,631
|
||||||||||||
|
Income per
common share ─
continuing
operations
|
862
|
59,575
|
||||||||||||||
|
Income (loss)
per common share ─ discontinued operations
|
3,021
|
(93
|
)
|
|||||||||||||
|
Net
income per common share
|
$
|
3,883
|
101,334
|
$
|
59,482
|
94,583
|
||||||||||