form10-q.htm
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 March 31, 2008
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: 001-07964
NOBLE
ENERGY, INC.
(Exact
name of registrant as specified in its charter)
Delaware
|
|
73-0785597
|
(State
of incorporation)
|
|
(I.R.S.
employer identification number)
|
|
|
|
100
Glenborough Drive, Suite 100
|
|
|
Houston,
Texas
|
|
77067
|
(Address
of principal executive offices)
|
|
(Zip
Code)
|
(281)
872-3100
(Registrant’s
telephone number, including area code)
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
[X] No [ ]
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 definition of “large accelerated filer”, “accelerated
filer” and “smaller reporting company” in
Rule
12b-2 of the Exchange Act. (Check one):
Large
accelerated filer [X]
|
Accelerated
filer [ ]
|
Non-accelerated
filer [ ]
|
Smaller
reporting company [ ]
|
|
(Do
not check if a smaller reporting
company)
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes
[ ] No [X]
Number
of shares of common stock outstanding as of April 15, 2008:
172,212,293.
PART
I. FINANCIAL INFORMATION
|
|
|
|
|
|
|
ITEM
1. FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noble
Energy, Inc. and Subsidiaries
|
|
Consolidated
Statements of Operations
|
|
(in
millions, except per share amounts)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
Revenues
|
|
|
|
|
|
|
Oil,
gas and NGL sales
|
|
$ |
944 |
|
|
$ |
667 |
|
Income
from equity method investees
|
|
|
62 |
|
|
|
46 |
|
Other
revenues
|
|
|
19 |
|
|
|
30 |
|
Total
|
|
|
1,025 |
|
|
|
743 |
|
Costs
and Expenses
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
82 |
|
|
|
79 |
|
Production
and ad valorem taxes
|
|
|
43 |
|
|
|
25 |
|
Transportation
expense
|
|
|
13 |
|
|
|
11 |
|
Exploration
expense
|
|
|
40 |
|
|
|
45 |
|
Depreciation,
depletion and amortization
|
|
|
203 |
|
|
|
166 |
|
General
and administrative
|
|
|
60 |
|
|
|
45 |
|
Other
operating expense, net
|
|
|
21 |
|
|
|
29 |
|
Total
|
|
|
462 |
|
|
|
400 |
|
Operating
Income
|
|
|
563 |
|
|
|
343 |
|
Other
(Income) Expense
|
|
|
|
|
|
|
|
|
Loss
(gain) on commodity derivative instruments
|
|
|
237 |
|
|
|
(1 |
) |
Interest,
net of amount capitalized
|
|
|
17 |
|
|
|
27 |
|
Other
(income) expense, net
|
|
|
(7 |
) |
|
|
13 |
|
Total
|
|
|
247 |
|
|
|
39 |
|
Income
Before Income Taxes
|
|
|
316 |
|
|
|
304 |
|
Income
Tax Provision
|
|
|
101 |
|
|
|
92 |
|
Net
Income
|
|
$ |
215 |
|
|
$ |
212 |
|
|
|
|
|
|
|
|
|
|
Earnings
Per Share
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.25 |
|
|
$ |
1.24 |
|
Diluted
|
|
$ |
1.20 |
|
|
$ |
1.22 |
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
172 |
|
|
|
171 |
|
Diluted
|
|
|
175 |
|
|
|
173 |
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
|
|
|
|
|
|
Noble
Energy, Inc. and Subsidiaries
|
|
Consolidated
Balance Sheets
|
|
(in
millions)
|
|
|
|
|
|
|
|
|
|
|
(unaudited)March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
ASSETS
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash
and cash equivalents
|
$ |
807
|
|
$ |
660
|
|
Accounts
receivable - trade, net
|
|
727
|
|
|
594
|
|
Deferred
income taxes
|
|
125
|
|
|
131
|
|
Other
current assets
|
|
117
|
|
|
184
|
|
Total
current assets
|
|
1,776
|
|
|
1,569
|
|
Property,
plant and equipment
|
|
|
|
|
|
|
Oil
and gas properties (successful efforts method of
accounting)
|
|
10,684
|
|
|
10,217
|
|
Other
property, plant and equipment
|
|
117
|
|
|
112
|
|
|
|
10,801
|
|
|
10,329
|
|
Accumulated
depreciation, depletion and amortization
|
|
(2,594)
|
|
|
(2,384)
|
|
Total
property, plant and equipment, net
|
|
8,207
|
|
|
7,945
|
|
Goodwill
|
|
759
|
|
|
761
|
|
Other
noncurrent assets
|
|
540
|
|
|
556
|
|
Total
Assets
|
$ |
11,282
|
|
$ |
10,831
|
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
Accounts
payable - trade
|
$ |
731
|
|
$
|
781
|
|
Commodity
derivative instruments
|
|
623
|
|
|
540
|
|
Other
current liabilities
|
|
429
|
|
|
315
|
|
Total
current liabilities
|
|
1,783
|
|
|
1,636
|
|
Deferred
income taxes
|
|
2,019
|
|
|
1,984
|
|
Asset
retirement obligations
|
|
148
|
|
|
131
|
|
Commodity
derivative instruments
|
|
109
|
|
|
83
|
|
Other
noncurrent liabilities
|
|
329
|
|
|
337
|
|
Long-term
debt
|
|
1,851
|
|
|
1,851
|
|
Total
Liabilities
|
|
6,239
|
|
|
6,022
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders’
Equity
|
|
|
|
|
|
|
Preferred
stock - par value $1.00; 4 million shares authorized, none
issued
|
|
-
|
|
|
-
|
|
Common
stock - par value $3.33 1/3; 250 million shares
authorized;
|
|
|
|
|
|
|
192
million and 191 million shares issued, respectively
|
|
639
|
|
|
636
|
|
Capital
in excess of par value
|
|
2,133
|
|
|
2,106
|
|
Accumulated
other comprehensive loss
|
|
(274)
|
|
|
(284)
|
|
Treasury
stock, at cost; 19 million shares
|
|
(613)
|
|
|
(613)
|
|
Retained
earnings
|
|
3,158
|
|
|
2,964
|
|
Total
Shareholders’ Equity
|
|
5,043
|
|
|
4,809
|
|
Total
Liabilities and Shareholders’ Equity
|
$ |
11,282
|
|
$ |
10,831
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
|
|
|
|
|
Noble
Energy, Inc. and Subsidiaries
|
|
Consolidated
Statements of Cash Flows
|
|
(in
millions)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
Cash
Flows From Operating Activities
|
|
|
|
|
|
|
Net
income
|
|
$ |
215 |
|
|
$ |
212 |
|
Adjustments
to reconcile net income to net cash
|
|
|
|
|
|
|
|
|
provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization - oil and gas production
|
|
|
203 |
|
|
|
166 |
|
Deferred
income taxes
|
|
|
35 |
|
|
|
48 |
|
Income
from equity method investees
|
|
|
(62 |
) |
|
|
(46 |
) |
Dividends
received from equity method investees
|
|
|
76 |
|
|
|
53 |
|
Unrealized
loss (gain) on commodity derivative instruments
|
|
|
218 |
|
|
|
(1 |
) |
Settlement
of previously recognized hedge losses
|
|
|
(62 |
) |
|
|
(51 |
) |
Other
|
|
|
20 |
|
|
|
58 |
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
(Increase)
in accounts receivable
|
|
|
(137 |
) |
|
|
(51 |
) |
(Increase)
decrease in other current assets
|
|
|
(5 |
) |
|
|
34 |
|
(Decrease)
increase in accounts payable
|
|
|
(61 |
) |
|
|
12 |
|
Increase
(decrease) in other current liabilities
|
|
|
66 |
|
|
|
(12 |
) |
Net
Cash Provided by Operating Activities
|
|
|
506 |
|
|
|
422 |
|
|
|
|
|
|
|
|
|
|
Cash
Flows From Investing Activities
|
|
|
|
|
|
|
|
|
Additions
to property, plant and equipment
|
|
|
(464 |
) |
|
|
(332 |
) |
Proceeds
from sale of property, plant and equipment
|
|
|
109 |
|
|
|
- |
|
Net
Cash Used in Investing Activities
|
|
|
(355 |
) |
|
|
(332 |
) |
|
|
|
|
|
|
|
|
|
Cash
Flows From Financing Activities
|
|
|
|
|
|
|
|
|
Exercise
of stock options
|
|
|
10 |
|
|
|
13 |
|
Excess
tax benefits from stock-based awards
|
|
|
9 |
|
|
|
8 |
|
Cash
dividends paid
|
|
|
(21 |
) |
|
|
(13 |
) |
Purchases
of treasury stock
|
|
|
(2 |
) |
|
|
(102 |
) |
Proceeds
from credit facilities
|
|
|
500 |
|
|
|
115 |
|
Repayment
of credit facilities
|
|
|
(500 |
) |
|
|
(115 |
) |
Proceeds
from short term borrowings, net
|
|
|
- |
|
|
|
100 |
|
Net
Cash (Used in) Provided by Financing Activities
|
|
|
(4 |
) |
|
|
6 |
|
Increase
in Cash and Cash Equivalents
|
|
|
147 |
|
|
|
96 |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
660 |
|
|
|
153 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
807 |
|
|
$ |
249 |
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
|
|
|
|
|
|
|
|
|
Noble
Energy, Inc. and Subsidiaries
|
|
Consolidated
Statements of Shareholders' Equity
|
|
(in
millions)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
of Stock
|
|
|
|
|
|
Capital
in
|
|
|
Other
|
|
|
Treasury
|
|
|
|
|
|
Total
|
|
|
|
Common
|
|
|
Treasury
|
|
|
Common
|
|
|
Excess
of
|
|
|
Comprehensive
|
|
|
Stock
|
|
|
Retained
|
|
|
Shareholders'
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Stock
|
|
|
Par
Value
|
|
|
Loss
|
|
|
at
Cost
|
|
|
Earnings
|
|
|
Equity
|
|
December
31, 2007
|
|
|
191 |
|
|
|
19 |
|
|
$ |
636 |
|
|
$ |
2,106 |
|
|
$ |
(284 |
) |
|
$ |
(613 |
) |
|
$ |
2,964 |
|
|
$ |
4,809 |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
215 |
|
|
|
215 |
|
Stock-based
compensation expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
|
Exercise
of stock options
|
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
|
|
8 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10 |
|
Tax
benefits related to exercise of stock options
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
|
Restricted
stock awards, net
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Dividends
($0.12 per share)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(21 |
) |
|
|
(21 |
) |
Changes
in treasury stock, net
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
Oil
and gas cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
amounts reclassified into earnings
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
38 |
|
|
|
- |
|
|
|
- |
|
|
|
38 |
|
Interest
rate cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
change in fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
(27 |
) |
Net
change in other
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
March
31, 2008
|
|
|
192 |
|
|
|
19 |
|
|
$ |
639 |
|
|
$ |
2,133 |
|
|
$ |
(274 |
) |
|
$ |
(613 |
) |
|
$ |
3,158 |
|
|
$ |
5,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2006
|
|
|
188 |
|
|
|
17 |
|
|
$ |
629 |
|
|
$ |
2,041 |
|
|
$ |
(140 |
) |
|
$ |
(511 |
) |
|
$ |
2,095 |
|
|
$ |
4,114 |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
212 |
|
|
|
212 |
|
Stock-based
compensation expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
Exercise
of stock options
|
|
|
1 |
|
|
|
- |
|
|
|
3 |
|
|
|
10 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
13 |
|
Tax
benefits related to exercise of stock options
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8 |
|
Restricted
stock awards, net
|
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
|
|
(2 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Dividends
($0.075 per share)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(13 |
) |
|
|
(13 |
) |
Purchases
of treasury stock
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(102 |
) |
|
|
- |
|
|
|
(102 |
) |
Oil
and gas cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
amounts reclassified into earnings
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(9 |
) |
|
|
- |
|
|
|
- |
|
|
|
(9 |
) |
Unrealized
change in fair value
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(63 |
) |
|
|
- |
|
|
|
- |
|
|
|
(63 |
) |
Net
change in other
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
March
31, 2007
|
|
|
190 |
|
|
|
19 |
|
|
$ |
634 |
|
|
$ |
2,062 |
|
|
$ |
(211 |
) |
|
$ |
(613 |
) |
|
$ |
2,294 |
|
|
$ |
4,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noble
Energy, Inc. and Subsidiaries
|
|
Consolidated
Statements of Comprehensive Income
|
|
(in
millions)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
215 |
|
|
$ |
212 |
|
Other
items of comprehensive income (loss)
|
|
|
|
|
|
|
|
|
Oil
and gas cash flow hedges
|
|
|
|
|
|
|
|
|
Realized
amounts reclassified into earnings
|
|
|
60 |
|
|
|
(15 |
) |
Less
tax provision
|
|
|
(22 |
) |
|
|
6 |
|
Unrealized
change in fair value
|
|
|
- |
|
|
|
(100 |
) |
Less
tax provision
|
|
|
- |
|
|
|
37 |
|
Interest
rate cash flow hedges
|
|
|
|
|
|
|
|
|
Unrealized
change in fair value
|
|
|
(43 |
) |
|
|
- |
|
Less
tax provision
|
|
|
16 |
|
|
|
- |
|
Net
change in other
|
|
|
(1 |
) |
|
|
1 |
|
Other
comprehensive income (loss)
|
|
|
10 |
|
|
|
(71 |
) |
Comprehensive
income
|
|
$ |
225 |
|
|
$ |
141 |
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
|
|
|
|
|
|
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1 – Organization and
Nature of Operations
Noble
Energy, Inc. (“Noble Energy”, “we” or “us”) is an independent energy company
engaged in the acquisition, exploration, development, production and marketing
of crude oil, natural gas and NGLs. We have exploration, exploitation and
production operations domestically and internationally. We operate throughout
major basins in the US including Colorado’s Wattenberg field and Piceance basin,
the Mid-continent region of western Oklahoma and the Texas Panhandle, the San
Juan Basin in New Mexico, the Gulf Coast and the Gulf of Mexico. In addition, we
conduct business internationally in China, Ecuador, the Mediterranean Sea, the
North Sea, West Africa (Equatorial Guinea and Cameroon) and in other
areas.
Note 2 – Basis of
Presentation
Presentation – The
accompanying unaudited consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the US for interim
financial information and with the instructions to Form 10-Q and Article 10 of
Regulation S-X. Accordingly, they do not include all of the information and
notes required by US generally accepted accounting principles (“GAAP”) for
complete financial statements. The accompanying consolidated financial
statements at March 31, 2008 (unaudited) and December 31, 2007 and for
the three months ended March 31, 2008 and 2007 contain all normally recurring
adjustments considered necessary for a fair presentation of our financial
position, results of operations and cash flows for such periods. Operating
results for the three-month period ended March 31, 2008 are not necessarily
indicative of the results that may be expected for the year ended December 31,
2008. Certain reclassifications of amounts previously reported have been made to
conform to current year presentations. These consolidated financial statements
should be read in conjunction with the consolidated financial statements and
accompanying notes included in our annual report on Form 10-K for the year
ended December 31, 2007.
Sale of Argentina Assets – In
February 2008, we closed on the sale of our interest in Argentina for a sales
price of $117.5 million, effective July 1, 2007. The gain on sale has been
deferred as the sale is contingent upon approval of the Argentine government.
The Argentina operations, financial position and cash flows are not material and
have not been reflected as discontinued operations.
Statements of Operations Information
– Other statements of operations information is as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Other
Revenues
|
|
|
|
|
|
|
Electricity
sales
|
|
$ |
15 |
|
|
$ |
23 |
|
Gathering,
marketing and processing revenues
|
|
|
4 |
|
|
|
7 |
|
Total
|
|
$ |
19 |
|
|
$ |
30 |
|
Other
Operating Expense, net
|
|
|
|
|
|
|
|
|
Electricity
generation expense
|
|
$ |
15 |
|
|
$ |
16 |
|
Gathering,
marketing and processing expense
|
|
|
5 |
|
|
|
5 |
|
Other
operating expense, net
|
|
|
1 |
|
|
|
8 |
|
Total
|
|
$ |
21 |
|
|
$ |
29 |
|
Other
(Income) Expense, net
|
|
|
|
|
|
|
|
|
Deferred
compensation (income) expense
|
|
$ |
(7 |
) |
|
$ |
12 |
|
Interest
income
|
|
|
(6 |
) |
|
|
(3 |
) |
Other
expense, net
|
|
|
6 |
|
|
|
4 |
|
Total
|
|
$ |
(7 |
) |
|
$ |
13 |
|
Balance Sheet Information –
Other balance sheet information is as follows:
|
March
31,
|
|
December
31,
|
|
|
2008
|
|
2007
|
|
|
(in
millions)
|
|
Other
Current Assets
|
|
|
|
|
|
Inventories
|
$ |
70 |
|
|
$ |
60 |
|
Commodity
derivative instruments
|
|
24 |
|
|
|
15 |
|
Prepaid
expenses and other current assets
|
|
21 |
|
|
|
25 |
|
Assets
held for sale
|
|
- |
|
|
|
82 |
|
Probable
insurance claims
|
|
2 |
|
|
|
2 |
|
Total
|
$ |
117 |
|
|
$ |
184 |
|
Other
Noncurrent Assets
|
|
|
|
|
|
|
|
Equity
method investments
|
$ |
343 |
|
|
$ |
357 |
|
Mutual
fund investments
|
|
118 |
|
|
|
124 |
|
Probable
insurance claims
|
|
37 |
|
|
|
37 |
|
Commodity
derivative instruments
|
|
10 |
|
|
|
5 |
|
Other
noncurrent assets
|
|
32 |
|
|
|
33 |
|
Total
|
$ |
540 |
|
|
$ |
556 |
|
Other
Current Liabilities
|
|
|
|
|
|
|
|
Accrued
and other current liabilities
|
$ |
222 |
|
|
$ |
206 |
|
Current
income taxes payable
|
|
84 |
|
|
|
52 |
|
Current
installment of long-term debt
|
|
25 |
|
|
|
25 |
|
Asset
retirement obligations
|
|
11 |
|
|
|
13 |
|
Interest
payable
|
|
19 |
|
|
|
18 |
|
Interest
rate lock derivative instruments
|
|
45 |
|
|
|
1 |
|
Deferred
gain on asset sale
|
|
23 |
|
|
|
- |
|
Total
|
$ |
429 |
|
|
$ |
315 |
|
Other
Noncurrent Liabilities
|
|
|
|
|
|
|
|
Deferred
compensation liability
|
$ |
214 |
|
|
$ |
225 |
|
Accrued
benefit costs
|
|
55 |
|
|
|
51 |
|
Other
noncurrent liabilities
|
|
60 |
|
|
|
61 |
|
Total
|
$ |
329 |
|
|
$ |
337 |
|
Adoption of SFAS 157 – We
adopted Statement of Financial Accounting Standards No. 157, “Fair Value
Measurements” (“SFAS 157”), as of January 1, 2008 as related to our
financial assets and liabilities. SFAS 157 establishes a single authoritative
definition of fair value based upon the assumptions market participants would
use when pricing an asset or liability and creates a fair value hierarchy that
prioritizes the information used to develop those assumptions. Under the
standard, additional disclosures are required, including disclosures of fair
value measurements by level within the fair value hierarchy. As a result of
adoption, we have begun incorporating our own credit standing into the
measurement of certain liabilities. Adoption did not have a significant impact
on our consolidated financial statements. See Note 3 – Fair Value Measurements.
We will adopt SFAS No. 157 as it relates to non-financial assets and liabilities
on January 1, 2009.
Adoption of SFAS 159 – We
adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities” (“SFAS 159”) as of January 1, 2008. SFAS No. 159 provides companies
with an option to report selected financial assets and liabilities at fair
value. Adoption had no effect on our financial position or results of operations
as we made no elections to report selected financial assets or liabilities at
fair value.
Adoption of FSP FIN 39-1 – We
adopted FSP FIN 39-1, “An Amendment of FASB Interpretation No. 39” (“FSP FIN
39-1”), as of January 1, 2008. FSP FIN 39-1 addresses certain modifications to
FIN 39, “Offsetting of Amounts Related to Certain Contracts.” FIN 39-1 allows
companies to offset fair value amounts recognized for derivative instruments and
the fair value amounts
recognized for the right to reclaim cash collateral or the obligation to return
cash collateral. The cash collateral must arise from derivative instruments
recognized at fair value that are executed with the same counterparty under a
master netting arrangement. Upon adoption, we elected to offset the right to
reclaim cash collateral or the obligation to return cash collateral against our
net derivative positions for which master netting agreements exist. As of March
31, 2008 and December 31, 2007, we had no significant cash collateral
obligations.
Note 3 – Fair Value
Measurements
Measurement
information for financial assets and liabilities reported at fair value at March
31, 2008, includes the following:
|
|
Fair
Value Measurements Using
|
|
|
|
|
|
|
|
|
Quoted
Prices in
|
|
|
Significant
Other
|
Significant
|
|
|
|
|
Fair
|
|
|
|
Active
Markets
|
|
|
Observable
Inputs
|
Unobservable
Inputs
|
Netting
|
|
Value
|
|
|
|
(Level
1)
|
|
|
(Level
2)
|
|
(Level
3)
|
|
|
Adjustment
(1)
|
|
Measurement
|
|
|
|
(in millions)
|
|
Financial
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mutual
fund investments
|
$ |
118
|
|
$ |
-
|
|
$ |
-
|
|
$ |
|
|
$ |
118
|
|
Commodity
derivative instruments
|
|
-
|
|
|
49
|
|
|
-
|
|
|
(15
|
) |
|
34
|
|
Financial
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative instruments
|
|
-
|
|
|
(747
|
) |
|
-
|
|
|
15
|
|
|
(732
|
) |
Interest
rate lock derivative instruments
|
|
-
|
|
|
(45
|
) |
|
-
|
|
|
-
|
|
|
(45
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amount represents the impact of legally enforceable
master netting agreements that allow
us to settle asset and liability positions with the same
counterparty.
|
|
SFAS
157, which we adopted as of January 1, 2008, establishes a fair value hierarchy
which prioritizes the inputs to valuation techniques used to measure fair value
into three levels. The fair value hierarchy gives the highest priority to quoted
market prices (unadjusted) in active markets for identical assets or liabilities
(Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2
inputs are inputs other than quoted prices included within Level 1 that are
observable for the asset or liability, either directly or indirectly. We use
Level 1 inputs when available, as Level 1 inputs generally provide the most
reliable evidence of fair value. We use the following methods and
assumptions to estimate the fair values of the assets and liabilities in the
table above:
Mutual Fund Investments – Our mutual fund investments
consist of various publicly-traded mutual funds that include investments ranging
from equities to money market instruments. The fair values are based on quoted
market prices.
Commodity Derivative Instruments –
Our commodity derivative instruments consist of variable to fixed price
swaps, costless collars and basis swaps. We estimate the fair values of these
instruments based on published forward commodity price curves for the underlying
commodities as of the date of the estimate. The discount rate used in the
discounted cash flow projections includes a measure of nonperformance risk. In
addition, for costless collars, we estimate the option value of the contract
floors and ceilings using an option pricing model which takes into account
market volatility, market prices and contract parameters. See Note 4 –
Derivative Instruments and Hedging Activities.
Interest Rate Lock Derivative
Instruments – We have interest rate locks of $1 billion notional value,
based on US Treasury rates. We estimate the fair values of the locks based on
published interest rate yield curves as of the date of the estimate. The
discount rate used in the discounted cash flow projections includes a measure of
nonperformance risk. See Note 4 – Derivative Instruments and Hedging
Activities.
Note 4 – Derivative
Instruments and Hedging Activities
Commodity Derivative Instruments
– We use various derivative instruments in connection with forecasted
crude oil and natural gas sales to minimize the impact of commodity price
fluctuations. Such instruments include variable to fixed price swaps, costless
collars and basis swaps. Although these derivative instruments may expose us to
credit risk, we monitor the creditworthiness
of our counterparties and believe that losses from nonperformance are unlikely
to be significant. However, we are not able to predict sudden changes in the
creditworthiness of our counterparties.
We
account for derivative instruments and hedging activities in accordance with
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as
amended, and all derivative instruments are reflected at fair value on our
consolidated balance sheets. We elected to designate certain of our commodity
derivative instruments as cash flow hedges through December 31, 2007. However,
effective January 1, 2008, we discontinued cash flow hedge accounting on
all existing commodity derivative instruments. We voluntarily made this change
to provide greater flexibility in our use of derivative instruments. From
January 1, 2008 forward, we recognize all gains and losses on such instruments
in earnings during the period in which they occur. Net derivative losses that
were deferred in accumulated other comprehensive income (loss) (“AOCL”) as of
December 31, 2007, as a result of previous cash flow hedge accounting, will be
reclassified to earnings in future periods as the original hedged transactions
occur. The discontinuance of cash flow hedge accounting for commodity derivative
instruments did not affect our net assets or cash flows at December 31, 2007 and
does not require adjustments to our previously reported financial
statements.
The
components of loss (gain) on commodity derivative instruments are as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Unrealized
loss on commodity derivative instruments
|
|
$ |
218 |
|
|
$ |
- |
|
Realized
loss on commodity derivative instruments
|
|
|
19 |
|
|
|
- |
|
Ineffectiveness
gain
|
|
|
- |
|
|
|
(1 |
) |
Loss
(gain) on commodity derivative instruments
|
|
$ |
237 |
|
|
$ |
(1 |
) |
Crude
oil and natural gas sales include amounts reclassified from AOCL as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Decrease
in crude oil sales
|
|
$ |
(97 |
) |
|
$ |
(28 |
) |
Increase
in natural gas sales
|
|
|
37 |
|
|
|
43 |
|
Total
(decrease) increase in oil and gas sales
|
|
$ |
(60 |
) |
|
$ |
15 |
|
As
of April 23, 2008, we had entered into the following crude oil derivative
instruments:
|
|
Variable
to Fixed Price Swaps
|
|
Costless
Collars |
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
Production
|
|
|
|
Bbls
|
|
|
Average
|
|
|
|
Bbls
|
|
|
Average
|
|
|
Average
|
|
Period
|
|
Index
|
|
Per
Day
|
|
|
Fixed
Price
|
|
Index
|
|
Per
Day
|
|
|
Floor
Price
|
|
|
Ceiling
Price
|
|
2nd
Qtr 2008
|
|
NYMEX
WTI
|
|
|
16,500 |
|
|
$ |
38.33 |
|
NYMEX
WTI
|
|
|
3,100 |
|
|
$ |
60.00 |
|
|
$ |
72.40 |
|
3rd
Qtr 2008
|
|
NYMEX
WTI
|
|
|
16,500 |
|
|
|
38.11 |
|
NYMEX
WTI
|
|
|
3,100 |
|
|
|
60.00 |
|
|
|
72.40 |
|
4th
Qtr 2008
|
|
NYMEX
WTI
|
|
|
16,500 |
|
|
|
37.92 |
|
NYMEX
WTI
|
|
|
3,100 |
|
|
|
60.00 |
|
|
|
72.40 |
|
2nd
Qtr 2008
|
|
Dated
Brent
|
|
|
2,000 |
|
|
|
88.18 |
|
Dated
Brent
|
|
|
4,220 |
|
|
|
45.00 |
|
|
|
66.65 |
|
3rd
Qtr 2008
|
|
Dated
Brent
|
|
|
2,000 |
|
|
|
88.18 |
|
Dated
Brent
|
|
|
3,848 |
|
|
|
45.00 |
|
|
|
66.19 |
|
4th
Qtr 2008
|
|
Dated
Brent
|
|
|
2,000 |
|
|
|
88.18 |
|
Dated
Brent
|
|
|
3,587 |
|
|
|
45.00 |
|
|
|
65.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
NYMEX
WTI
|
|
|
9,000 |
|
|
|
88.43 |
|
NYMEX
WTI
|
|
|
4,700 |
|
|
|
68.51 |
|
|
|
79.11 |
|
2009
|
|
Dated
Brent
|
|
|
2,000 |
|
|
|
87.98 |
|
Dated
Brent
|
|
|
3,074 |
|
|
|
45.00 |
|
|
|
63.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
NYMEX
WTI
|
|
|
5,500 |
|
|
|
69.00 |
|
|
|
85.65 |
|
As
of April 23, 2008, we had entered into the following natural gas derivative
instruments:
|
|
Variable
to Fixed Price Swaps
(1)
|
|
Costless
Collars
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
Production
|
|
|
|
MMBtu
|
|
|
Average
|
|
|
|
MMBtu
|
|
|
Average
|
|
|
Average
|
|
Period
|
|
Index
|
|
Per
Day
|
|
|
Fixed
Price
|
|
Index
|
|
Per
Day
|
|
|
Floor
Price
|
|
|
Ceiling
Price
|
|
2nd
Qtr 2008
|
|
NYMEX
HH
|
|
|
170,000 |
|
|
$ |
5.34 |
|
IFERC
CIG
|
|
|
14,000 |
|
|
$ |
6.75 |
|
|
$ |
8.70 |
|
3rd
Qtr 2008
|
|
NYMEX
HH
|
|
|
170,000 |
|
|
|
5.33 |
|
IFERC
CIG
|
|
|
14,000 |
|
|
|
6.75 |
|
|
|
8.70 |
|
4th
Qtr 2008
|
|
NYMEX
HH
|
|
|
170,000 |
|
|
|
5.63 |
|
IFERC
CIG
|
|
|
14,000 |
|
|
|
6.75 |
|
|
|
8.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
NYMEX
HH
|
|
|
120,000 |
|
|
|
8.74 |
|
|
|
10.49 |
|
2009
|
|
|
|
|
|
|
|
|
|
|
IFERC
CIG
|
|
|
15,000 |
|
|
|
6.00 |
|
|
|
9.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
IFERC
CIG
|
|
|
15,000 |
|
|
|
6.25 |
|
|
|
8.10 |
|
(1)
|
In
addition to the NYMEX HH variable to fixed price swaps shown above for
2008, we have 100,000 MMBtu per day of IFERC CIG basis swaps with an
average differential to NYMEX HH of $(1.66) per MMBtu, 40,000 MMBtu per
day of IFERC ANR-OK basis swaps with an average differential to NYMEX HH
of $(1.01) per MMBtu, and 10,000 MMBtu per day of IFERC PEPL
basis swaps with an average differential to NYMEX HH of $(0.98) per
MMBtu.
|
Approximately
$180 million of deferred losses (net of taxes) related to the fair values of the
commodity derivative instruments previously designated as cash flow hedges and
remaining in AOCL at March 31, 2008 will be reclassified to earnings during the
next 12 months as the forecasted transactions occur, and will be recorded as a
reduction in oil and gas sales.
Interest Rate Lock Derivative Instruments
–
We have entered into two interest rate swaps, or interest rate “locks”,
each in the notional amount of $500 million. The locks are based on five and ten
year US Treasury rates of 3.55% and 4.15%, respectively, and expire in September
2008. The locks are designated as cash flow hedges and changes in their fair
values are reported in AOCL, to the extent the hedges are effective, until the
forecasted transactions occur. At that time, we will begin recording the amounts
remaining in AOCL as adjustments to interest expense. At March 31, 2008,
AOCL included a deferred loss of $28 million, net of tax, related to these
interest rate locks.
Note 5 – Capitalized
Exploratory Well Costs
Changes
in capitalized exploratory well costs during the period were as
follows:
|
Three
Months Ended
|
|
|
March
31, 2008 (1)
|
|
|
|
(in
millions)
|
|
Capitalized
exploratory well costs at beginning of period
|
|
$ |
249 |
|
Additions
to capitalized exploratory well costs pending determination of proved
reserves
|
|
|
31 |
|
Reclassified
to property, plant and equipment based on determination of proved
reserves
|
|
|
- |
|
Capitalized
exploratory well costs charged to expense
|
|
|
- |
|
Capitalized
exploratory well costs at end of period
|
|
$ |
280 |
|
(1)
|
Changes
in capitalized exploratory well costs exclude amounts that were
capitalized and subsequently expensed in the same
period.
|
The
following table provides an aging of capitalized exploratory well costs
(suspended well costs) based on the date the drilling was completed and the
number of projects for which exploratory well costs have been capitalized for a
period greater than one year since the completion of drilling:
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Capitalized
exploratory well costs that have been capitalized for a period
of one year or less
|
|
$ |
203 |
|
|
$ |
187 |
|
Capitalized
exploratory well costs that have been capitalized for a period
greater than one year after completion of drilling
|
|
|
77 |
|
|
|
62 |
|
Balance
at end of period
|
|
$ |
280 |
|
|
$ |
249 |
|
Number
of projects that have exploratory well costs that have
been capitalized for a period greater than one year after
completion of drilling
|
|
|
7 |
|
|
|
6 |
|
The
following table provides a further aging of those exploratory well costs that
have been capitalized for a period greater than one year since the completion of
drilling as of March 31, 2008:
|
|
|
|
|
Suspended
Since
|
|
|
|
Total
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in
millions)
|
|
Project
|
|
|
|
|
|
|
|
|
|
|
|
|
Raton
South (deepwater Gulf of Mexico)
|
|
$ |
23 |
|
|
$ |
- |
|
|
$ |
23 |
|
|
$ |
- |
|
Redrock
(deepwater Gulf of Mexico)
|
|
|
17 |
|
|
|
- |
|
|
|
17 |
|
|
|
- |
|
Blocks
O and I (West Africa)
|
|
|
19 |
|
|
|
- |
|
|
|
- |
|
|
|
19 |
|
Flyndre
(North Sea)
|
|
|
15 |
|
|
|
12 |
|
|
|
3 |
|
|
|
- |
|
Other
|
|
|
3 |
|
|
|
- |
|
|
|
3 |
|
|
|
- |
|
Total
capitalized exploratory well costs that have been capitalized
for a period greater than one year since completion of
drilling
|
|
$ |
77 |
|
|
$ |
12 |
|
|
$ |
46 |
|
|
$ |
19 |
|
Exploratory
well costs capitalized for more than one year at March 31, 2008 included seven
projects, two of which included activity in the deepwater Gulf of
Mexico. One project relates to Raton South (Mississippi Canyon Block
292) and includes $23 million of suspended exploratory well costs. We are
currently evaluating a possible sidetrack-appraisal well to be drilled during
late 2008 or 2009. The other project relates to Redrock (Mississippi
Canyon Block 204) and includes $17 million of suspended exploratory well costs.
Redrock is currently considered a co-development candidate to a successful
sidetrack-appraisal well at Raton South. In addition, we are currently
evaluating options to tie back to subsea pipelines and other
facilities.
We
also incurred exploratory well costs for the Blocks O and I projects in West
Africa. These exploratory well costs totaled $19 million. Since drilling the
initial well for the project, additional seismic work has been completed and
exploration and appraisal wells have been drilled to further evaluate our
discoveries. The West Africa development team is proceeding with a program to
further define the resources in this area such that an optimal development
program may be designed. In addition to the amount of exploratory well costs
that have been capitalized for a period greater than one year for the Block O
and Block I projects, we have incurred $160 million in suspended costs related
to additional drilling activity in West Africa through March 31,
2008.
Another
project, Flyndre, is located in the UK sector of the North Sea and incurred
exploratory well costs of $15 million. We successfully completed an
exploratory appraisal well in 2007 and we are working with the operator to
formulate a development plan.
The
remaining two projects, which total $3 million in suspended exploratory well
costs, continue to be evaluated by various means including additional seismic
work, drilling additional wells and evaluating the potential of the exploration
wells.
Note 6 – Asset Retirement
Obligations
Asset
retirement obligations consist primarily of estimated costs of dismantlement,
removal, site reclamation and similar activities associated with our oil and gas
properties. Changes in asset retirement obligations were as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31, 2008
|
|
|
|
(in
millions)
|
|
Asset
retirement obligations at beginning of period
|
|
$ |
144 |
|
Liabilities
incurred in current period
|
|
|
14 |
|
Liabilities
settled in current period
|
|
|
(4 |
) |
Revisions
|
|
|
3 |
|
Accretion
expense
|
|
|
2 |
|
Asset
retirement obligations at end of period
|
|
$ |
159 |
|
Accretion
expense is included in depreciation, depletion and amortization expense in the
consolidated statements of operations.
Note 7 – Employee Benefit
Plans
We
have a noncontributory, tax-qualified defined benefit pension plan covering
employees who were hired prior to May 1, 2006. We also have an unfunded, nonqualified restoration plan that provides the pension plan
formula benefits that cannot be provided by the qualified pension plan because
of pay deferrals and the compensation and benefit limitations imposed on the
pension plan by the Internal Revenue Code of 1986, as amended. Net periodic
benefit cost related to the retirement and restoration plans was as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Service
cost
|
|
$ |
3 |
|
|
$ |
3 |
|
Interest
cost
|
|
|
3 |
|
|
|
3 |
|
Expected
return on plan assets
|
|
|
(3 |
) |
|
|
(3 |
) |
Other
|
|
|
- |
|
|
|
1 |
|
Net
periodic benefit cost
|
|
$ |
3 |
|
|
$ |
4 |
|
Note 8 – Stock-Based
Compensation
We
recognized stock-based compensation expense as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Stock-based
compensation expense
|
|
$ |
9 |
|
|
$ |
5 |
|
Tax
benefit recognized
|
|
|
(3 |
) |
|
|
(2 |
) |
During
the three months ended March 31, 2008, we granted 1,114,288 stock options with a
weighted-average grant-date fair value of $20.34 per share and awarded 438,976
shares of restricted stock subject to service conditions with a weighted-average
grant-date fair value of $72.98 per share.
Note 9 – Basic and Diluted
Earnings Per Share
Basic
earnings per share of common stock were computed using the weighted average
number of shares of common stock outstanding during each period. The diluted
earnings per share of common stock include the effect of outstanding stock
options and restricted stock, except in periods in which there is a net
loss. The following table summarizes the calculation of basic and diluted
earnings per share:
|
|
Three
Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Weighted
|
|
|
|
Net
|
|
|
Average
|
|
|
Net
|
|
|
Average
|
|
|
|
Income
|
|
|
Shares
|
|
|
Income
|
|
|
Shares
|
|
|
|
(in
millions, except per share amounts)
|
|
Net
income
|
|
$ |
215 |
|
|
|
172 |
|
|
$ |
212 |
|
|
|
171 |
|
Basic
Earnings Per Share
|
|
$ |
1.25 |
|
|
|
|
|
|
$ |
1.24 |
|
|
|
|
|
Net
income
|
|
$ |
215 |
|
|
|
172 |
|
|
$ |
212 |
|
|
|
171 |
|
Plus
incremental shares from assumed conversions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive
options, restricted stock awards and shares of common stock in rabbi
trust
|
|
|
(4 |
) |
|
|
3 |
|
|
|
- |
|
|
|
2 |
|
Net
income available to common shareholders
|
|
$ |
211 |
|
|
|
175 |
|
|
$ |
212 |
|
|
|
173 |
|
Diluted
Earnings Per Share
|
|
$ |
1.20 |
|
|
|
|
|
|
$ |
1.22 |
|
|
|
|
|
A
total of 1.2 million weighted average stock options and restricted shares were
antidilutive for first quarter 2008 and were excluded from the calculation of
diluted earnings per share. A total of 2.5 million weighted average
stock options, restricted shares and shares of our common stock held in a rabbi
trust were antidilutive for first quarter 2007 and were excluded from the
calculation of diluted earnings per share.
Note 10
– Income
Taxes
The
income tax provision consists of the following:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Current
|
|
$ |
66 |
|
|
$ |
44 |
|
Deferred
|
|
|
35 |
|
|
|
48 |
|
Total
income tax provision
|
|
$ |
101 |
|
|
$ |
92 |
|
Unrecognized Tax Positions
– We do not have
significant unrecognized tax benefits as of March 31, 2008. Our policy is to
recognize any interest and penalties related to unrecognized tax benefits in
income tax expense. We did not accrue interest or penalties at March 31, 2008,
because the jurisdiction in which we have unrecognized tax benefits does not
currently impose interest on underpayments of tax, and we believe that we are
below the minimum statutory threshold for imposition of penalties.
In
our major tax jurisdictions, the earliest years remaining open to examination
are as follows: US - 2004, Equatorial Guinea - 2006, China - 2006, Israel -
2000, UK - 2006 and the Netherlands - 2005.
Note 11 – Segment
Information
We
have operations throughout the world and manage our operations by country. The
following information is grouped into five components that are all primarily in
the business of natural gas and crude oil acquisition, exploration and
production: the United States, West Africa, the North Sea, Israel,
and Other International, Corporate and Marketing. Other International includes
Argentina, China, Ecuador and Suriname. The following data was prepared on the
same basis as our consolidated financial statements and excludes the effects of
income taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Int'l
|
|
|
|
|
|
|
United
|
|
|
West
|
|
|
North
|
|
|
|
|
|
Corporate
&
|
|
|
|
Consolidated
|
|
|
States
|
|
|
Africa
|
|
|
Sea
|
|
|
Israel
|
|
|
Marketing
|
|
|
|
(in
millions)
|
|
Three
Months Ended March 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from third parties (1)
|
|
$ |
963 |
|
|
$ |
529 |
|
|
$ |
129 |
|
|
$ |
92 |
|
|
$ |
40 |
|
|
$ |
173 |
|
Intersegment
revenue
|
|
|
- |
|
|
|
116 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(116 |
) |
Income
from equity method investments
|
|
|
62 |
|
|
|
- |
|
|
|
62 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Revenues
|
|
|
1,025 |
|
|
|
645 |
|
|
|
191 |
|
|
|
92 |
|
|
|
40 |
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
203 |
|
|
|
164 |
|
|
|
9 |
|
|
|
16 |
|
|
|
6 |
|
|
|
8 |
|
Loss
on commodity derivative instruments
|
|
|
237 |
|
|
|
209 |
|
|
|
28 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Income
(loss) before income taxes
|
|
|
316 |
|
|
|
145 |
|
|
|
150 |
|
|
|
55 |
|
|
|
31 |
|
|
|
(65 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from third parties (1)
|
|
$ |
697 |
|
|
$ |
398 |
|
|
$ |
64 |
|
|
$ |
55 |
|
|
$ |
25 |
|
|
$ |
155 |
|
Intersegment
revenue
|
|
|
- |
|
|
|
96 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(96 |
) |
Income
from equity method investments
|
|
|
46 |
|
|
|
- |
|
|
|
46 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Revenues
|
|
|
743 |
|
|
|
494 |
|
|
|
110 |
|
|
|
55 |
|
|
|
25 |
|
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
|
|
|
166 |
|
|
|
140 |
|
|
|
3 |
|
|
|
12 |
|
|
|
4 |
|
|
|
7 |
|
Gain
on commodity derivative instruments
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Income
(loss) before income taxes
|
|
|
304 |
|
|
|
218 |
|
|
|
83 |
|
|
|
32 |
|
|
|
20 |
|
|
|
(49 |
) |
Total
assets at March 31, 2008
(2)
|
|
$ |
11,282 |
|
|
$ |
8,276 |
|
|
$ |
1,472 |
|
|
$ |
588 |
|
|
$ |
272 |
|
|
$ |
674 |
|
Total
assets at December 31, 2007(2)
|
|
|
10,831 |
|
|
|
7,918 |
|
|
|
1,355 |
|
|
|
562 |
|
|
|
268 |
|
|
|
728 |
|
(1)
|
The
US reporting unit includes a $48 million decrease to revenues for first
quarter 2008 and a $15 million increase to revenues for first quarter 2007
from hedging activities. The West Africa reporting unit includes a $12
million decrease to revenues for first quarter 2008 from hedging
activities. Hedging activities had no effect on West Africa revenues first
quarter 2007. The 2008 decreases resulted from hedge gains and losses that
were deferred in AOCL as of December 31, 2007 and subsequently
reclassified to revenues.
|
(2)
|
The
US reporting unit includes goodwill of $759 million at March 31, 2008 and
$761 million at December 31, 2007.
|
Note 12 – Commitments and
Contingencies
Legal Proceedings – We are
among a group of 18 defendants named in a lawsuit filed August 23, 2002 by Dore
Energy Corporation under Docket Number 10-16202 in the 38th Judicial District
Court, Cameron Parish, Louisiana. The lawsuit alleges damage to
property owned by Dore resulting from oil and gas activities dating to the
1930’s. Our predecessor, Samedan Oil Corporation, operated on a
portion of the property from 1989 to 1999. Dore has delivered
documents alleging approximately $140 million in damages. By order
dated April 15, 2008, the April 14, 2008 trial was postponed without the setting
of a new date. We intend to vigorously defend against these allegations and
believe that our share of damages, if any, will not have a material adverse
effect on our financial position, results of operations, or cash
flows.
We are involved in various other legal proceedings in the ordinary
course of business. These proceedings are subject to the
uncertainties inherent in any litigation. We are defending
ourselves vigorously in all such matters and we do not believe that the
ultimate disposition of such proceedings will have a material adverse effect on
our financial position, results of operations or cash flows.
Note 13 – Recently Issued
Pronouncements
SFAS
141(R) and SFAS 160 – In December 2007, the FASB issued SFAS 141(R),
“Business Combinations” (“SFAS 141(R)”) and SFAS 160, “Noncontrolling Interests
in Consolidated Financial Statements” (“SFAS 160”). These statements require
most identifiable assets, liabilities and noncontrolling interests to be
recorded at full fair value and require noncontrolling interests to be
reported as a component of equity. Both statements are effective for periods
beginning on or after December 15, 2008, and earlier adoption is prohibited.
SFAS 141(R) will be applied to business combinations occurring after the
effective date and SFAS 160 will be applied prospectively to all noncontrolling
interests, including any that arose before the effective date. We are currently
evaluating the provisions of SFAS 141(R) and SFAS 160 and assessing the impact,
if any, they may have on our financial position and results of
operations.
SFAS 161 – In March 2008, the
FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging
Activities” (“SFAS 161”). SFAS 161 amends and expands the disclosure
requirements of SFAS 133 and requires qualitative disclosures about objectives
and strategies for using derivatives, quantitative disclosures about fair value
amounts of derivative instruments and related gains and losses, and disclosures
about credit-risk-related contingent features in derivative agreements. SFAS 161
is effective for financial statements issued for fiscal years and interim
periods beginning after November 15, 2008. We are currently evaluating the
provisions of SFAS 161. The statement provides only for enhanced disclosures.
Therefore, adoption will have no impact on our financial position or results of
operations.
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION
AND
RESULTS OF OPERATIONS
EXECUTIVE
OVERVIEW
We
are a worldwide producer of crude oil, natural gas and NGLs. Our strategy is to
achieve growth in earnings and cash flow through the development of a high
quality portfolio of producing assets that is diversified among domestic and
international projects.
Effective
January 1, 2008, we discontinued cash flow hedge accounting on all existing
commodity derivative instruments. We voluntarily made this change to provide
greater flexibility in our use of derivative instruments. From January 1, 2008
forward, we recognize all gains and losses on such instruments in earnings in
the period in which they occur. The discontinuance of cash flow hedge accounting
for commodity derivative instruments has no impact on our net assets or cash
flows and previously reported amounts have not been adjusted. However, the use
of mark-to-market accounting adds volatility to our reported earnings. For first
quarter 2008, net income included an unrealized $218 million mark-to-market loss
on commodity derivative instruments.
First
quarter 2008 financial results also included the following:
|
·
|
net
income of $215 million, as compared with $212 million for first quarter
2007;
|
|
·
|
diluted
earnings per share of $1.20, as compared with $1.22 for first quarter
2007; and
|
|
·
|
cash
flow from operating activities of $506 million, as compared with $422
million for first quarter 2007.
|
First
quarter 2008 operational results included the following:
|
·
|
a
22% overall increase in sales volumes over first quarter
2007;
|
|
·
|
continued
production growth in the Rocky Mountain area of our US
operations;
|
|
·
|
record
natural gas sales in Israel;
|
|
·
|
new
Ticonderoga development wells brought online in the deepwater Gulf of
Mexico; and
|
|
·
|
successful
high bids on 15 deepwater lease blocks in the Central Gulf of Mexico Lease
Sale 206.
|
OUTLOOK
We
expect crude oil, natural gas and condensate production to increase in 2008
compared to 2007. The expected year-over-year increase in production is impacted
by several factors including:
|
·
|
higher
sales of natural gas from the Alba field in Equatorial
Guinea;
|
|
·
|
growing
production from our Rocky Mountain assets, where we are continuing active
drilling programs;
|
|
·
|
natural
field decline in the Gulf Coast and Mid-continent areas of our US
operations.
|
Factors
impacting our expected production profile for 2008 include:
|
·
|
potential
hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast
areas of our US operations;
|
|
·
|
potential
winter storm-related volume curtailments in the Northern region of our US
operations;
|
|
·
|
potential
pipeline and processing facility capacity constraints in the Rocky
Mountain area of our US operations;
|
|
·
|
infrastructure
development in Israel;
|
|
·
|
potential
downtime at the methanol, LPG and/or LNG facilities in Equatorial
Guinea;
|
|
·
|
seasonal
variations in rainfall in Ecuador that affect our natural gas-to-power
project; and
|
|
·
|
timing
of capital expenditures, as discussed below, which are expected to result
in near-term production.
|
2008
Capital Expenditures – We have forecasted capital expenditures of
approximately $1.9 billion for 2008. Approximately 33% of the 2008
capital forecast has been allocated to exploration opportunities, including
additions for the deepwater lease sale and other leasehold acquisitions.
Approximately 67% of the 2008 capital forecast has been allocated to production,
development and other projects. US expenditures are forecast at $1.4 billion,
international expenditures are forecast at $463 million
and corporate expenditures are forecast at $31 million. We expect that our 2008
capital forecast will be funded primarily from cash flows from operations and
borrowings under our revolving credit facility. We will evaluate the level of
capital spending throughout the year based upon drilling results, commodity
prices, cash flows from operations, and property acquisitions and
divestitures.
Recently Issued
Pronouncements –
See Item 1. Financial Statements – Note 13 – Recently Issued
Pronouncements.
RESULTS
OF OPERATIONS
Oil,
Gas and NGL Sales
Average
daily sales volumes and average realized sales prices were as
follows:
|
|
Sales
Volumes
|
|
|
Average
Realized Sales Prices
|
|
|
|
Crude
Oil &
|
|
|
Natural
|
|
|
|
|
|
Crude
Oil &
|
|
|
Natural
|
|
|
|
|
|
|
Condensate
|
|
|
Gas
(1)
|
|
|
NGLs
(1)
|
|
|
Condensate
|
|
|
Gas
(1)
|
|
|
NGLs
(1)
|
|
|
|
(MBopd)
|
|
|
(MMcfpd)
|
|
|
(MBpd)
|
|
|
(Per
Bbl)
|
|
|
(Per
Mcf)
|
|
|
(Per
Bbl)
|
|
Three
Months Ended March 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States (2)
|
|
|
43 |
|
|
|
393 |
|
|
|
9 |
|
|
$ |
71.33 |
|
|
$ |
8.97 |
|
|
$ |
55.15 |
|
West
Africa (3)
|
|
|
15 |
|
|
|
220 |
|
|
|
- |
|
|
|
88.79 |
|
|
|
0.27 |
|
|
|
- |
|
North
Sea
|
|
|
9 |
|
|
|
6 |
|
|
|
- |
|
|
|
100.46 |
|
|
|
9.65 |
|
|
|
- |
|
Israel
|
|
|
- |
|
|
|
145 |
|
|
|
- |
|
|
|
- |
|
|
|
3.04 |
|
|
|
- |
|
Ecuador
(4)
|
|
|
- |
|
|
|
23 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other
International
|
|
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
73.37 |
|
|
|
- |
|
|
|
- |
|
Total
Consolidated Operations
|
|
|
73 |
|
|
|
787 |
|
|
|
9 |
|
|
|
78.89 |
|
|
|
5.34 |
|
|
|
55.15 |
|
Equity
Investees (5)
|
|
|
2 |
|
|
|
- |
|
|
|
6 |
|
|
|
98.55 |
|
|
|
- |
|
|
|
60.78 |
|
Total
|
|
|
75 |
|
|
|
787 |
|
|
|
15 |
|
|
$ |
79.43 |
|
|
$ |
5.34 |
|
|
$ |
57.47 |
|
Three
Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States (2)
|
|
|
46 |
|
|
|
408 |
|
|
|
- |
|
|
$ |
46.42 |
|
|
$ |
8.24 |
|
|
$ |
- |
|
West
Africa (3)
|
|
|
12 |
|
|
|
55 |
|
|
|
- |
|
|
|
56.25 |
|
|
|
0.36 |
|
|
|
- |
|
North
Sea
|
|
|
9 |
|
|
|
7 |
|
|
|
- |
|
|
|
60.85 |
|
|
|
6.02 |
|
|
|
- |
|
Israel
|
|
|
- |
|
|
|
103 |
|
|
|
- |
|
|
|
- |
|
|
|
2.73 |
|
|
|
- |
|
Ecuador
(4)
|
|
|
- |
|
|
|
30 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other
International
|
|
|
7 |
|
|
|
1 |
|
|
|
- |
|
|
|
45.24 |
|
|
|
1.00 |
|
|
|
- |
|
Total
Consolidated Operations
|
|
|
74 |
|
|
|
604 |
|
|
|
- |
|
|
|
49.73 |
|
|
|
6.46 |
|
|
|
- |
|
Equity
Investees (5)
|
|
|
2 |
|
|
|
- |
|
|
|
5 |
|
|
|
59.35 |
|
|
|
- |
|
|
|
39.25 |
|
Total
|
|
|
76 |
|
|
|
604 |
|
|
|
5 |
|
|
$ |
49.96 |
|
|
$ |
6.46 |
|
|
$ |
39.25 |
|
(1)
|
For
2007, domestic NGL sales volumes were included with natural gas
volumes. Effective in 2008, we began reporting domestic NGLs,
which has lowered the comparative natural gas volumes from 2007 to
2008.
|
(2)
|
Average
realized crude oil and condensate prices reflect reductions of $21.81 per
Bbl for first quarter 2008 and $6.85 per Bbl for first quarter 2007 from
hedging activities. Average realized natural gas prices reflect increases
of $1.05 per Mcf for first quarter 2008 and $1.17 per Mcf for first
quarter 2007 from hedging activities. The 2008 price reductions
and increases resulted from hedge gains and losses that were deferred in
AOCL as of December 31, 2007.
|
(3)
|
Average
realized crude oil and condensate prices reflect reductions of $8.62 per
Bbl for first quarter 2008 from hedging activities. The 2008
price reductions resulted from hedge losses that were deferred in AOCL as
of December 31, 2007. Hedging activities had no effect on West
Africa prices in first quarter 2007. Natural gas from the Alba
field in Equatorial Guinea is under contract for $0.25 per MMBtu to a
methanol plant, an LPG plant and an LNG facility. The methanol and LPG
plants are owned by affiliated entities accounted for under the equity
method of accounting. Natural gas volumes sold to the LNG
facility totaled 173 MMcfpd during first quarter 2008 and 1 MMcfpd during
first quarter 2007. The natural gas sold to the LNG facility and methanol
plant has a lower Btu content than the natural gas sold to the LPG plant.
As a result of the increase in natural gas volumes sold to the LNG
plant in 2008, the average price received on an Mcf basis is
lower.
|
(4)
|
The
natural gas-to-power project in Ecuador is 100% owned by our subsidiaries
and intercompany natural gas sales are eliminated for accounting purposes.
Electricity sales of $15 million and $23 million are included in other
revenues for first quarter 2008 and 2007,
respectively.
|
(5)
|
Volumes
represent sales of condensate and LPG from the Alba plant in Equatorial
Guinea. See Equity Method Investees
below.
|
Crude
oil and condensate sales volumes in the table above differ from actual
production volumes due to the timing of liquid hydrocarbon tanker liftings.
Crude oil and condensate production volumes were as follows:
|
|
Three
Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(MBopd)
|
|
United
States
|
|
|
43 |
|
|
|
46 |
|
West
Africa
|
|
|
15 |
|
|
|
16 |
|
North
Sea
|
|
|
11 |
|
|
|
9 |
|
Other
International
|
|
|
6 |
|
|
|
8 |
|
Total
Consolidated Operations
|
|
|
75 |
|
|
|
79 |
|
Equity
Investees
|
|
|
2 |
|
|
|
2 |
|
Total
|
|
|
77 |
|
|
|
81 |
|
Revenues
from sales of commodities were as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Crude
oil and condensate sales
|
|
$ |
527 |
|
|
$ |
333 |
|
Natural
gas sales
|
|
|
371 |
|
|
|
334 |
|
NGL
sales (1)
|
|
|
46 |
|
|
|
- |
|
Total
|
|
$ |
944 |
|
|
$ |
667 |
|
(1)
|
For
2007, domestic NGL sales volumes were included with natural gas
volumes. Effective in 2008, we began reporting domestic NGLs,
which has lowered the comparative natural gas volumes from 2007 to
2008.
|
Crude Oil and Condensate Sales –
Sales of crude oil and condensate increased a net $194 million, or 58%,
during first quarter 2008 as compared with first quarter 2007 due primarily to
higher worldwide commodity prices. US sales increased by $88 million, or 46%,
from first quarter 2007. However, the effect of commodity price increases was
offset by a net decrease in US sales volumes. Growth in the Rocky Mountain area
was offset by declining production in the Gulf Coast onshore and Mid-continent
areas.
International
sales increased $106 million, or 74%, due to higher average realized prices and
an increase in West Africa sales volumes due to the timing of hydrocarbon tanker
liftings.
Revenues
for first quarter 2008 and 2007 included decreases of $97 million and $28
million, respectively, reclassified from AOCL and related to commodity
derivative instruments which were accounted for as cash flow hedges through
December 31, 2007.
Natural Gas Sales – Natural gas sales increased
a net $37 million, or 11%, during first quarter 2008 as compared with first
quarter 2007. The increase was driven by both volume and price changes. US sales
increased $17 million, or 6%, from first quarter 2007 primarily due to an
increase in prices. Our successful drilling program in the Piceance basin along
with less severe winter weather in the Rocky Mountain area resulted in increased
US production in 2008, which was offset somewhat by declining production in the
Gulf Coast onshore and Mid-continent areas. These volume
increases were also offset by a reduction for shrink gas associated
with the natural gas liquids now being reported separately.
International
sales increased $20 million, or 63%, due to record production levels and higher
prices in Israel and increased sales from the Alba field in Equatorial Guinea to
an LNG plant. These factors were partially offset by lower average realized
prices in West Africa.
Revenues
for first quarter 2008 and 2007 included increases of $37 million and $43
million, respectively, reclassified from AOCL and related to commodity
derivative instruments which were accounted for as cash flow hedges through
December 31, 2007.
Equity
Method Investees
Our
share of operations of equity method investees, Atlantic Methanol Production
Company, LLC (“AMPCO”) and Alba Plant LLC (“Alba Plant”), was as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
Net
income (in millions):
|
|
|
|
|
|
|
AMPCO
|
|
$ |
28 |
|
|
$ |
25 |
|
Alba
Plant
|
|
$ |
34 |
|
|
$ |
21 |
|
Distributions/dividends
(in millions):
|
|
|
|
|
|
|
|
|
AMPCO
|
|
$
|
34 |
|
|
$ |
21 |
|
Alba
Plant
|
|
$ |
42 |
|
|
$ |
32 |
|
Production
volumes:
|
|
|
|
|
|
|
|
|
Methanol
(Mgal)
|
|
|
34 |
|
|
|
40 |
|
Condensate
(MBopd)
|
|
|
2 |
|
|
|
2 |
|
LPG
(MBpd)
|
|
|
6 |
|
|
|
6 |
|
Sales
volumes:
|
|
|
|
|
|
|
|
|
Methanol
(Mgal)
|
|
|
34 |
|
|
|
40 |
|
Condensate
(MBopd)
|
|
|
2 |
|
|
|
2 |
|
LPG
(MBpd)
|
|
|
6 |
|
|
|
5 |
|
Average
realized prices:
|
|
|
|
|
|
|
|
|
Methanol
(per gallon)
|
|
$ |
1.63 |
|
|
$ |
1.22 |
|
Condensate
(per Bbl)
|
|
$ |
98.55 |
|
|
$ |
59.35 |
|
LPG
(per Bbl)
|
|
$ |
60.78 |
|
|
$ |
39.25 |
|
For
first quarter 2008, net income from AMPCO increased $3 million, or 12%, relative
to 2007 due to higher average realized methanol prices offset by a decrease in
methanol sales volumes. The decrease in methanol sales volumes was due to a 20
day shutdown of methanol production for compressor maintenance.
For
first quarter 2008, net income from Alba Plant increased $13 million, or 62%,
relative to 2007 due to higher average realized condensate and LPG prices,
offset by the expiration of the Alba Plant tax holiday at the end of
2007.
Costs
and Expenses
Production Costs – Production
costs were as follows:
|
|
|
|
|
United
|
|
|
West
|
|
|
North
|
|
|
|
|
|
Other
Int'l /
|
|
|
|
Consolidated
|
|
States
|
|
|
Africa
|
|
|
Sea
|
|
|
Israel
|
|
|
Corporate(1)
|
|
|
|
(in
millions)
|
|
Three
Months Ended March 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas operating costs (2)
|
|
$ |
76 |
|
|
$ |
49 |
|
|
$ |
9 |
|
|
$ |
11 |
|
|
$ |
2 |
|
|
$ |
5 |
|
Workover
and repair expense
|
|
|
6 |
|
|
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Lease
operating expense
|
|
|
82 |
|
|
|
55 |
|
|
|
9 |
|
|
|
11 |
|
|
|
2 |
|
|
|
5 |
|
Production
and ad valorem taxes
|
|
|
43 |
|
|
|
33 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10 |
|
Transportation
expense
|
|
|
13 |
|
|
|
11 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
Total
production costs
|
|
$ |
138 |
|
|
$ |
99 |
|
|
$ |
9 |
|
|
$ |
13 |
|
|
$ |
2 |
|
|
$ |
15 |
|
Three
Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas operating costs (2)
|
|
$ |
75 |
|
|
$ |
55 |
|
|
$ |
7 |
|
|
$ |
6 |
|
|
$ |
2 |
|
|
$ |
5 |
|
Workover
and repair expense
|
|
|
4 |
|
|
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Lease
operating expense
|
|
|
79 |
|
|
|
59 |
|
|
|
7 |
|
|
|
6 |
|
|
|
2 |
|
|
|
5 |
|
Production
and ad valorem taxes
|
|
|
25 |
|
|
|
20 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
Transportation
expense
|
|
|
11 |
|
|
|
8 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
1 |
|
Total
production costs
|
|
$ |
115 |
|
|
$ |
87 |
|
|
$ |
7 |
|
|
$ |
8 |
|
|
$ |
2 |
|
|
$ |
11 |
|
(1)
|
Other
international includes Ecuador, China, and
Argentina.
|
(2)
|
Oil
and gas operating costs include labor, fuel, repairs, replacements,
saltwater disposal and other related lifting
costs.
|
Total
production costs increased $23 million, or 20%, first quarter 2008 as compared
with first quarter 2007. The increase in production and ad valorem taxes was
driven primarily by higher worldwide commodity prices and also by an increase in
volumes subject to such taxes. US lease operating expense declined
from 2007 primarily due to a decrease in insurance costs for our Gulf of Mexico
deepwater operations related to a change in insurance coverage made during
second quarter 2007. This reduction was offset by expenses relating
to increased workover activity and higher costs related to the continuing active
drilling program in the Northern region. North Sea oil and gas operating costs
increased due to expanded operations.
Selected
expenses on a per BOE basis were as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
Oil
and gas operating costs
|
|
$ |
3.88 |
|
|
$ |
4.75 |
|
Workover
and repair expense
|
|
|
0.33 |
|
|
|
0.25 |
|
Lease
operating expense
|
|
|
4.21 |
|
|
|
5.00 |
|
Production
and ad valorem taxes
|
|
|
2.23 |
|
|
|
1.60 |
|
Transportation
expense
|
|
|
0.68 |
|
|
|
0.70 |
|
Total
production costs (1) (2)
(3)
|
|
$ |
7.12 |
|
|
$ |
7.30 |
|
(1)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees.
|
(2)
|
Sales
volumes include natural gas sales to an LNG facility in Equatorial Guinea
that began late first quarter 2007. The inclusion of these volumes reduced
the unit rate by $1.11 per BOE for first quarter 2008 and had no effect on
first quarter 2007.
|
(3)
|
Natural
gas volumes are converted to oil equivalent volumes on the basis of six
Mcf per barrel of oil.
|
Oil and Gas Exploration Expense –
Oil and gas exploration expense consists of dry hole expense, unproved
lease amortization, seismic expense, staff expense and other miscellaneous
exploration expense, including lease rentals. Oil and gas exploration
expense decreased $5 million during first quarter 2008 as compared with first
quarter 2007 as a result of a $13 million decrease in dry hole expense, offset
by a $3 million increase in seismic expense and a $6 million increase in other
exploration expense.
Depreciation, Depletion and
Amortization – Depreciation, depletion and amortization (“DD&A”)
expense was as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions, except unit rate)
|
|
DD&A
expense - property, plant and equipment
|
|
$ |
201 |
|
|
$ |
164 |
|
Accretion
of discount on asset retirement obligations
|
|
|
2 |
|
|
|
2 |
|
Total
DD&A expense
|
|
$ |
203 |
|
|
$ |
166 |
|
Unit
rate per BOE (1)
(2)
|
|
$ |
10.42 |
|
|
$ |
10.55 |
|
(1)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees.
|
(2)
|
Sales
volumes include natural gas sales to an LNG facility in Equatorial Guinea
that began late first quarter 2007. The inclusion of these volumes reduced
the unit rate by $1.32 per BOE for first quarter 2008 and had no effect on
first quarter 2007.
|
Total
DD&A expense for first quarter 2008 increased as compared to first quarter
2007 primarily due to the increase in production volumes. The decrease in the
unit rate is due to a change in the mix of production.
General and Administrative
Expense – General and administrative expense (“G&A”) was as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
G&A
expense (in millions)
|
|
$ |
60 |
|
|
$ |
45 |
|
Unit
rate per BOE (1)
(2)
|
|
$ |
3.09 |
|
|
$ |
2.86 |
|
(1)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees.
|
(2)
|
Sales
volumes include natural gas sales to an LNG facility in Equatorial Guinea
that began late first quarter 2007. The inclusion of these volumes reduced
the unit rate by $0.48 per BOE for first quarter 2008 and had no effect
for first quarter 2007.
|
G&A
expense increased $15 million, or 33%, during first quarter 2008 as compared
with first quarter 2007. One reason for the increase was higher
salaries and wages resulting from an increase in the number of employees to
address our increased activities. In addition, we have increased our accruals
for incentive compensation to align with current expectations of achievement,
and stock-based compensation increased $4 million from first quarter
2007.
Other Operating Expense, Net –
See Item I. Financial Statements - Note 2 – Basis of
Presentation.
Loss (Gain) on Commodity Derivative
Instruments – See Item 1. Financial Statements - Note 4 – Derivative
Instruments and Hedging Activities.
Interest Expense and Capitalized
Interest – Interest expense and capitalized interest were as
follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Interest
expense
|
|
$ |
27 |
|
|
$ |
31 |
|
Capitalized
interest
|
|
|
(10 |
) |
|
|
(4 |
) |
Interest
expense, net
|
|
$ |
17 |
|
|
$ |
27 |
|
Interest
expense decreased during first quarter 2008, as compared with first quarter 2007
due to a declining rate of interest applicable to our credit facility from 5.67%
at March 31, 2007 to 2.99% at March 31, 2008 and a slightly lower average
outstanding debt balance. The amount of interest capitalized
increased due to long lead-time projects in West Africa and the Gulf of
Mexico.
Other (Income) Expense, Net –
See Item 1. Financial Statements - Note 2 – Basis of
Presentation.
Income Tax Provision – The
income tax provision was as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
Income
tax provision (in millions)
|
|
$ |
101 |
|
|
$ |
92 |
|
Effective
rate
|
|
|
32 |
% |
|
|
30 |
% |
Our
effective tax rate increased during first quarter 2008 as compared with first
quarter 2007. This is due to the fact that our pretax income increased
significantly, but our favorable permanent adjustments (which reduce income tax
expense) did not increase at the same rate. One factor contributing to this
effect was that in Equatorial Guinea, our tax holiday for the Alba plant expired
at the end of 2007.
LIQUIDITY AND CAPITAL
RESOURCES
Overview
Our
primary cash needs are to fund operating expenses and capital expenditures
related to the acquisition, exploration and development of crude oil and natural
gas properties, to repay outstanding borrowings and associated interest payments
and other contractual commitments and to pay dividends. Traditional sources of
our liquidity are cash on hand, cash flows from operations and available
borrowing capacity under credit facilities. Occasional sales of non-strategic
crude oil and natural gas properties may also generate cash.
Cash and Cash Equivalents –
We had $807 million in cash and cash equivalents at March 31, 2008, compared
with $660 million at December 31, 2007. Substantially all of this cash is
located in our foreign subsidiaries and would be subject to additional US income
taxes if repatriated. The cash is denominated in US dollars and is invested in
highly liquid, investment-grade securities with original maturities of three
months or less at the time of purchase. We currently intend to use our
international cash to fund international projects, including the development of
West Africa.
We
are monitoring the current conditions in the credit markets. We have reviewed
the creditworthiness of the banks and financial institutions with which we
maintain our investments as well as the securities underlying our investments.
Thus far, our liquidity and financial position have not been negatively
impacted. We believe that losses from nonperformance are unlikely to occur;
however, we are not able to predict sudden changes in
creditworthiness.
Fair Value Measurements – As
of March 31, 2008, we had a net liability of $698 million relating to commodity
derivative instruments. We estimated the fair value of this liability in
accordance with SFAS 157, which we adopted as of January 1, 2008. In order to
determine the fair value at the end of each reporting period, we prepare a
discounted cash flow projection for the duration of each commodity derivative
instrument using the terms of the related contract. Inputs consist of published
forward commodity price curves for the underlying commodities as of the date of
the estimate. We compare these prices to the price parameters contained in our
hedge contracts to determine estimated future cash inflows (outflows). We then
discount the cash inflows (outflows) using a combination of LIBOR rates,
Eurodollar futures rates and interest swap rates. We adjust the discount rate
used to value our commodity derivative liabilities to include a measure of
non-performance risk, consisting of the current published credit default swap
spread on our public debt. In addition, for costless collars, we estimate the
option value of the contract floors and ceilings using an option pricing model
which takes into account market volatility, market prices and contract
parameters.
Beginning
January 1, 2008, we use mark-to-market accounting for our commodity derivative
instruments and recognize all changes in fair values in earnings in the period
they occur. This can have a significant impact on our results of operations due
to the volatility of the underlying commodity prices. Our liquidity is impacted
by current period settlements since we are either paying cash to, or receiving
cash from, our counterparties. Generally, if actual commodity prices are higher
than the fixed or ceiling prices in our derivative instruments, our cash flows
provided by operating activities will be lower than if we had no derivative
instruments. See additional information included in Item 3. Quantitative and
Qualitative Disclosures about Market Risk.
Cash
Flows
Cash
flow information is as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Total
cash provided by (used in):
|
|
|
|
|
|
|
Operating
activities
|
|
$ |
506 |
|
|
$ |
422 |
|
Investing
activities
|
|
|
(355 |
) |
|
|
(332 |
) |
Financing
activities
|
|
|
(4 |
) |
|
|
6 |
|
Increase
in cash and cash equivalents
|
|
$ |
147 |
|
|
$ |
96 |
|
Operating Activities – Net
cash provided by operating activities was $506 million for first quarter 2008,
as compared with $422 million for first quarter 2007. The increase
was due primarily to higher commodity prices.
Investing Activities – Net
cash used in investing activities was $355 million for first quarter 2008, as
compared with $332 million for first quarter 2007. Investing
activities in 2008 consisted of $464 million in capital expenditures offset by
$109 million in proceeds from asset sales. Investing activities in 2007
consisted entirely of capital expenditures. See Acquisition, Capital and Other
Exploration Expenditures below.
Financing Activities – Net
cash used in financing activities was $4 million for first quarter 2008, as
compared with $6 million provided by financing activities for first quarter
2007. During 2008 and 2007, cash used to pay dividends was offset by
cash received from the exercise of stock options. In addition, there were net
proceeds from borrowings of $100 million in 2007, while there were no net
proceeds from borrowings during 2008. In 2008, $2 million was used to repurchase
common stock as compared with $102 million used in 2007.
Investing
Activities
Acquisition, Capital and Other
Exploration Expenditures – Expenditure information (on an accrual basis)
is as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(in
millions)
|
|
Capital
Expenditures
|
|
|
|
|
|
|
Unproved
property acquisition
|
|
$ |
176 |
|
|
$ |
3 |
|
Exploration
expenditures
|
|
|
45 |
|
|
|
62 |
|
Development
expenditures
|
|
|
246 |
|
|
|
210 |
|
Corporate
and other expenditures
|
|
|
19 |
|
|
|
9 |
|
Total
capital expenditures
|
|
$ |
486 |
|
|
$ |
284 |
|
The
increase in unproved property acquisition cost relates primarily to deepwater
lease blocks acquired in the recent Gulf of Mexico lease sale.
Sale of Argentina Assets – In
February 2008, effective July 1, 2007, we sold our interest in Argentina for a
sales price of $117.5 million. The sale is subject to Argentine government
approval.
Financing
Activities
Long-Term Debt – Our
long-term debt totaled $1.9 billion (net of unamortized discount) at
March 31, 2008. Maturities range from 2011 to 2097. Our ratio of
debt-to-book capital was 27% at March 31, 2008 as compared with 28% at December
31, 2007. We define our ratio of debt-to-book capital as total debt (which
includes both long-term debt, excluding unamortized discount, and short-term
borrowings) divided by the sum of total debt plus shareholders’
equity.
Our
principal source of liquidity is a $2.1 billion unsecured revolving credit
facility. The commitment is
$2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8
billion. The credit facility (i) provides for credit facility fee rates
that range from 5 basis points to 15 basis points per year depending upon our
credit rating, (ii) makes available short-term loans up to an aggregate amount
of $300 million and (iii) provides for interest rates that are based upon the
Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis
points depending upon our credit rating and utilization of the credit facility.
The credit facility is with certain commercial lending institutions and is
available for general corporate purposes. At March 31, 2008, $1.2
billion in borrowings were outstanding under the credit facility. The
weighted average interest rate applicable to borrowings under the credit
facility at March 31, 2008 was 2.99%.
Installment Payments Due – We
owe $50 million in the form of installment payments to the seller of properties
we purchased in 2007. Installments of $25 million each are due on May 12, 2008
and May 11, 2009. The amount due in 2008 is included in short-term
borrowings and the amount due in 2009 is included in long-term debt in the
consolidated balance sheets. Interest on the unpaid amounts is due quarterly and
accrues at a LIBOR rate plus .30%. The interest rate was 5.13% at
March 31, 2008.
Short-Term Borrowings – Our
credit facility is supplemented by short-term borrowings under various
uncommitted credit lines used for working capital purposes. Uncommitted credit
lines may be offered by certain banks from time to time at rates negotiated at
the time of borrowing. Other than the installment payments discussed
above, there were no short-term borrowings outstanding at March 31,
2008.
Dividends – We paid a
quarterly cash dividend of 12.0 cents per share of common stock during first
quarter 2008 and 7.5 cents per share of common stock during first quarter 2007.
On April 21, 2008, our Board of Directors declared an increase in our quarterly
cash dividend by 50% to 18.0 cents per common share, payable May 19, 2008 to
shareholders of record on May 5, 2008. The amount of future dividends will be
determined on a quarterly basis at the discretion of our Board of Directors and
will depend on earnings, financial condition, capital requirements and other
factors.
Exercise of Stock Options –
We received $10 million from the exercise of stock options during first
quarter 2008 as compared to $13 million during first quarter 2007.
Common Stock Repurchases –
During first quarter 2008, we received from employees 24,000 shares of
common stock with a total value of $2 million for the payment of withholding
taxes due on shares issued under stock-based compensation
plans. During first quarter 2007, we repurchased 2 million shares of
our common stock at an aggregate cost of $102 million, pursuant to a common
stock repurchase program. The repurchase program was completed in
2007.
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT
MARKET RISK
Commodity
Price Risk
Derivative Instruments Held for
Non-Trading Purposes – We are exposed to market risk in the normal course
of business operations. We believe that we are well positioned with our mix of
crude oil and natural gas reserves to take advantage of future price increases
that may occur. However, the uncertainty of crude oil and natural gas prices
continues to impact the oil and gas industry. Due to the volatility of crude oil
and natural gas prices, we continue to use derivative instruments as a means of
managing our exposure to price changes.
At
March 31, 2008, we had entered into variable to fixed price swaps, costless
collars and basis swaps related to crude oil and natural gas
sales. Our open commodity derivative instruments were in a net
liability position with a fair value of $698 million. Based on the March 31,
2008 published forward commodity price curves for the underlying commodities,
simultaneous price increases of $1.00 per Bbl for crude oil and $0.10 per MMBtu
for natural gas would increase the fair value of our net commodity derivative
liability by approximately $23 million. See Item 1. Financial Statements -
Note 4 – Derivative Instruments and Hedging Activities.
Interest
Rate Risk
We
are exposed to interest rate risk related to our variable and fixed interest
rate debt. At March 31, 2008, we had $1.9 billion (excluding unamortized
discount) of long-term debt outstanding, of which $650 million was fixed-rate
debt with a weighted average interest rate of 6.92%. We believe that anticipated
near term changes in interest rates would not have a material effect on the fair
value of our fixed-rate debt and would not expose us to the risk of material
earnings or cash flow loss.
The
remainder of our long-term debt, $1.2 billion at March 31, 2008, was
variable-rate debt. We also had $25 million of current installment payments at
March 31, 2008. Variable rate debt exposes us to the risk of earnings or cash
flow loss due to changes in market interest rates. We estimate that a
hypothetical 25 basis point change in the floating interest rates applicable to
our March 31, 2008 balance of variable-rate debt would result in a change in
annual interest expense of approximately $3 million.
We
occasionally enter into forward contracts or swap agreements to hedge exposure
to interest rate risk. Changes in fair value of interest rate swaps or interest
rate “locks” used as cash flow hedges are reported in AOCL, to the extent the
hedge is effective, until the forecasted transaction occurs, at which time they
are recorded as adjustments to interest expense. At March 31, 2008,
AOCL included $31 million, net of tax, related to interest rate locks. A
portion of this amount is currently being reclassified into earnings as
adjustments to interest expense over the term of our 5¼% Senior Notes due
April 2014. The remainder relates to interest rate locks that are scheduled
to settle during third quarter 2008. See Note 4 – Derivative Instruments and
Hedging Activities.
We
are also exposed to interest rate risk related to our short-term investments. As
of March 31, 2008, substantially all of our cash was invested in highly liquid,
short-term investment-grade securities with original maturities of three months
or less at the time of purchase. A hypothetical 25 basis point change in the
floating interest rates applicable to the March 31, 2008 balance would result in
a change in annual interest income of approximately $2 million.
Foreign
Currency Risk
We
have not entered into foreign currency derivatives. The US dollar is considered
the functional currency for each of our international operations. Transactions
that are completed in a foreign currency are remeasured into US dollars and
recorded in the financial statements at prevailing currency exchange rates. We
do not have any significant monetary assets or liabilities denominated in a
foreign currency other than our foreign deferred tax liabilities in certain
foreign tax jurisdictions. An increase in exchange rates between the US dollar
and the currency of the foreign tax jurisdiction in which these liabilities are
located could result in the use of additional cash to settle these liabilities.
However, transaction gains or losses were not material in any of the periods
presented and we do not believe we are currently exposed to any material risk of
loss on this basis.
Such gains or losses are included in other (income) expense, net in the
consolidated statements of operations.
DISCLOSURE
REGARDING FORWARD-LOOKING STATEMENTS
This
quarterly report on Form 10-Q contains forward-looking statements within the
meaning of the federal securities laws. Forward-looking statements give our
current expectations or forecasts of future events. These forward-looking
statements include, among others, the following:
|
·
|
our
ability to successfully and economically explore for and develop crude oil
and natural gas resources;
|
|
·
|
anticipated
trends in our business;
|
|
·
|
our
future results of operations;
|
|
·
|
our
liquidity and ability to finance our exploration and development
activities;
|
|
·
|
market
conditions in the oil and gas
industry;
|
|
·
|
our
ability to make and integrate acquisitions;
and
|
|
·
|
the
impact of governmental regulation.
|
Forward-looking
statements are typically identified by use of terms such as “may,” “will,”
“expect,” “anticipate,” “estimate” and similar words, although some
forward-looking statements may be expressed differently. These forward-looking
statements are made based upon our current plans, expectations, estimates,
assumptions and beliefs concerning future events impacting us and therefore
involve a number of risks and uncertainties. We caution that forward-looking
statements are not guarantees and that actual results could differ materially
from those expressed or implied in the forward-looking statements. You should
consider carefully the statements under Item 1A. Risk Factors included herein,
if any, and included in our 2007 annual report on Form 10-K, which describe
factors that could cause our actual results to differ from those set forth in
the forward-looking statements. Our 2007 annual report on Form 10-K
is available on our website at www.nobleenergyinc.com.
ITEM
4. CONTROLS AND PROCEDURES
Based
on the evaluation of our disclosure controls and procedures by Charles D.
Davidson, our principal executive officer, and Chris Tong, our principal
financial officer, as of the end of the period covered by this quarterly report,
each of them has concluded that our disclosure controls and procedures, as
defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended,
are effective. There were no changes in internal control over financial
reporting that occurred during the quarter covered by this report that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
PART
II. OTHER INFORMATION
ITEM
1. LEGAL PROCEEDINGS
See
Item I. Financial Statements - Note 12 – Commitments and
Contingencies.
ITEM
1A. RISK FACTORS
None.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
|
|
|
|
|
|
|
Total
Number of
|
|
|
Approximate
Dollar
|
|
|
|
|
|
|
|
|
|
Shares
Purchased
|
|
|
Value
of Shares that
|
|
|
|
Total
Number (1)
|
|
|
Average
Price
|
|
|
as
Part of Publicly
|
|
|
May
Yet Be
|
|
|
|
of
Shares
|
|
|
Paid
|
|
|
Announced
Plans
|
|
|
Purchased
Under the
|
|
Period
|
|
Purchased
|
|
|
Per
Share
|
|
|
or
Programs
|
|
|
Plans
or Programs
|
|
|
|
|
|
|
|
|
|
(in
thousands)
|
|
01/01/08
- 01/31/08
|
|
|
4,665 |
|
|
$ |
80.33 |
|
|
|
- |
|
|
|
- |
|
02/01/08
- 02/29/08
|
|
|
19,715 |
|
|
|
73.02 |
|
|
|
- |
|
|
|
- |
|
03/01/08
- 03/31/08
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
24,380 |
|
|
$ |
74.42 |
|
|
|
- |
|
|
|
- |
|
(1)
|
Stock
repurchases during the period related to stock received by us from
employees for the payment of withholding taxes due on shares issued under
stock-based compensation plans.
|
ITEM
3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
|
ITEM
5. OTHER INFORMATION
None.
ITEM
6. EXHIBITS
The
information required by this Item 6 is set forth in the Index to Exhibits
accompanying this quarterly report on Form 10-Q.
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934 as amended, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
|
|
|
NOBLE
ENERGY, INC.
(Registrant)
|
Date
|
May
1, 2008
|
|
/s/
CHRIS TONG
|
|
|
|
CHRIS
TONG
Senior
Vice President and Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
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INDEX TO
EXHIBITS
31.1
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Certification
of the Company’s Chief Executive Officer Pursuant To Section 302 of the
Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
7241).
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31.2
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Certification
of the Company’s Chief Financial Officer Pursuant To Section 302 of the
Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
7241).
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32.1
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Certification
of the Company’s Chief Executive Officer Pursuant To Section 906 of the
Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
1350).
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32.2
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Certification
of the Company’s Chief Financial Officer Pursuant To Section 906 of the
Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
1350).
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