FORM 10-K
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
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or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-1204
Hess Corporation
(Exact name of Registrant as
specified in its charter)
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DELAWARE
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13-4921002
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification Number)
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1185 AVENUE OF THE AMERICAS,
NEW YORK, N.Y.
(Address of principal
executive offices)
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10036
(Zip
Code)
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(Registrants telephone number, including area code, is
(212) 997-8500)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock (par value $1.00)
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
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 þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of Registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(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 o No þ
The aggregate market value of voting stock held by
non-affiliates of the Registrant amounted to $16,463,000,000 as
of June 30, 2007.
At December 31, 2007, there were 320,599,585 shares of
Common Stock outstanding.
Part III is incorporated by reference from the Proxy
Statement for the annual meeting of stockholders to be held on
May 7, 2008.
HESS
CORPORATION
Form 10-K
TABLE OF
CONTENTS
1
PART I
Items 1
and 2. Business and Properties
Hess Corporation (the Registrant) is a Delaware corporation,
incorporated in 1920. The Registrant and its subsidiaries
(collectively referred to as the Corporation or
Hess) is a global integrated energy company that
operates in two segments, Exploration and Production (E&P)
and Marketing and Refining (M&R). The E&P segment
explores for, develops, produces, purchases, transports and
sells crude oil and natural gas. These exploration and
production activities take place principally in Algeria,
Australia, Azerbaijan, Brazil, Denmark, Egypt, Equatorial
Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway,
Russia, Thailand, the United Kingdom and the United States. The
M&R segment manufactures, purchases, transports, trades and
markets refined petroleum products, natural gas and electricity.
The Corporation owns 50% of a refinery joint venture in the
United States Virgin Islands, and another refining facility,
terminals and retail gasoline stations, most of which include
convenience stores, located on the East Coast of the United
States.
Exploration
and Production
The Corporations total proved reserves at December 31 were
as follows:
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Crude Oil and
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Total Barrels of Oil
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Natural Gas Liquids
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Natural Gas
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Equivalent (BOE)*
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2007
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2006
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2007
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2006
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2007
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2006
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(Millions of barrels)
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(Millions of mcf)
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(Millions of barrels)
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United States
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204
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138
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270
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236
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249
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178
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Europe
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329
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340
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656
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677
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438
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453
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Africa
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285
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304
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87
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300
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304
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Asia and other
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67
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50
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1,655
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1,553
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343
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308
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885
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832
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2,668
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2,466
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1,330
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1,243
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* |
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Reflects natural gas reserves
converted on the basis of relative energy content (six mcf
equals one barrel). |
On a barrel of oil equivalent (boe) basis, 44% of the
Corporations worldwide proved reserves are undeveloped at
December 31, 2007 (40% at December 31, 2006). Proved
reserves held under production sharing contracts at
December 31, 2007 totaled 25% of crude oil and natural gas
liquids and 57% of natural gas reserves.
Worldwide crude oil, natural gas liquids and natural gas
production was as follows:
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2007
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2006
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2005
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Crude oil (thousands of barrels per day)
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United States
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Onshore
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15
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15
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21
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Offshore
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16
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21
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23
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31
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36
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44
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Europe
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United Kingdom
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38
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50
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54
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Norway
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19
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22
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26
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Denmark
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12
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19
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24
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Russia
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24
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18
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6
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93
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109
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110
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2
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2007
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2006
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2005
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Africa
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Equatorial Guinea
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56
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28
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30
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Algeria
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22
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22
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25
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Gabon
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14
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12
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12
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Libya
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23
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23
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115
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85
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67
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Asia and other
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Azerbaijan
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16
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7
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4
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Other
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5
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5
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3
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21
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12
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7
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Total
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260
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242
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228
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Natural gas liquids (thousands of barrels per day)
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United States
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10
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10
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12
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Europe
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United Kingdom
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4
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4
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3
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Norway
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1
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1
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1
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5
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5
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4
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Total
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15
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15
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16
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Natural gas (thousands of mcf per day)
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United States
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Onshore
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42
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54
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74
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Offshore
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46
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|
56
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63
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88
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110
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137
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Europe
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United Kingdom
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231
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244
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222
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Norway
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18
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22
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28
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Denmark
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10
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17
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24
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259
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283
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274
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Asia and other
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Joint Development Area of Malaysia and Thailand (JDA)
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115
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131
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51
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Thailand
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90
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60
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57
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Indonesia
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59
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26
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25
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Other
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2
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2
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266
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219
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133
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Total
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613
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612
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544
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Barrels of oil equivalent*
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377
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359
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335
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* |
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Reflects natural gas production
converted on the basis of relative energy content (six mcf
equals one barrel). |
The Corporation presently estimates that its 2008 production
will be approximately 380,000 to 390,000 barrels of oil
equivalent per day (boepd). The Corporation is developing a
number of oil and gas fields and has an inventory of domestic
and foreign exploration prospects.
3
United
States
At December 31, 2007, 19% of the Corporations total
proved reserves were located in the United States. During 2007,
15% of the Corporations crude oil and natural gas liquids
production and 14% of its natural gas production were from
United States operations. The Corporations production in
the United States was principally from properties offshore in
the Gulf of Mexico, which include the Llano (Hess 50%), Conger
(Hess 37.5%), Baldpate (Hess 50%), Hack Wilson (Hess 33.3%) and
Penn State (Hess 50%) fields, onshore in North Dakota including
interests in the Bakken Play and Williston Basin and the
Seminole-San Andres Unit (Hess 34.3%) onshore Texas in the
Permian Basin.
The Shenzi development (Hess 28%) in the Green Canyon area of
the deepwater Gulf of Mexico was sanctioned by the operator in
2006 and progressed in 2007 with installation of the tension leg
platform tendon piles and hull fabrication. First production
from Shenzi is expected to commence in mid-2009. In February
2007, the Corporation completed the acquisition of a 28%
interest in the Genghis Khan oil and gas development located in
the deepwater Gulf of Mexico on Green Canyon Blocks 652 and
608. The Genghis Khan development is part of the same geological
structure as the Shenzi development. These fields were unitized
in 2007. Crude oil production from the Genghis Khan Field
commenced in October 2007.
Development of a residual oil zone at the
Seminole-San Andres Unit commenced in the fourth quarter of
2007 and it is anticipated that production from this development
will begin in 2009. The Corporation intends to inject carbon
dioxide gas supplied from its interests in the West Bravo Dome
and Bravo Dome fields in New Mexico into the residual oil zone
to enhance recovery of crude oil.
At the Corporations Tubular Bells prospect (Hess 20%)
located in the Mississippi Canyon area of the deepwater Gulf of
Mexico a successful sidetrack to the second Tubular Bells well
was completed during the first quarter of 2007 and the drilling
of a third well commenced in October 2007. On the Pony prospect
on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf
of Mexico a sidetrack from the original discovery well was
successfully completed in the first quarter of 2007 and a second
appraisal well is being drilled about 1.5 miles northwest
of the original discovery well.
At December 31, 2007, the Corporation has interests in more
than 370 exploration blocks in the Gulf of Mexico, which include
1,372,529 net undeveloped acres.
Europe
At December 31, 2007, 33% of the Corporations total
proved reserves were located in Europe (United Kingdom 11%,
Norway 14%, Denmark 3% and Russia 5%). During 2007, 36% of the
Corporations crude oil and natural gas liquids production
and 42% of its natural gas production were from European
operations.
United Kingdom: Production of crude oil
and natural gas liquids from the United Kingdom North Sea was
principally from the Corporations non-operated interests
in the Beryl (Hess 22.2%), Bittern (Hess 28.3%), Schiehallion
(Hess 15.7%) and Clair (Hess 9.3%) fields. Natural gas
production from the United Kingdom in 2007 was primarily from
fields in the Easington Catchment Area (Hess 28.8%), as well as
the Everest (Hess 18.7%), Lomond (Hess 16.7%), Beryl (Hess
22.2%), Atlantic (Hess 25%) and Cromarty (Hess 90%) fields.
In 2007, the Corporation completed the sale of its interests in
the Scott and Telford fields located offshore United Kingdom.
Norway: Substantially all of the 2007
and 2006 Norwegian production was from the Corporations
interest in the Valhall Field (Hess 28.1%). A field
redevelopment for Valhall was sanctioned during 2007. In
September 2007, gas production commenced at the Snohvit Field
(Hess 3.26%) located offshore Norway.
Denmark: Crude oil and natural gas
production comes from the Corporations interest in the
South Arne Field (Hess 57.5%).
Russia: The Corporations
activities in Russia are conducted through its 80%-owned
interest in a corporate joint venture operating in the
Volga-Urals region of Russia.
4
Africa
At December 31, 2007, 22% of the Corporations total
proved reserves were located in Africa (Equatorial Guinea 9%,
Algeria 2%, Libya 10% and Gabon 1%). During 2007, 42% of the
Corporations crude oil and natural gas liquids production
was from African operations.
Equatorial Guinea: The Corporation is
the operator and owns an interest in Block G (Hess 85%) which
contains the Ceiba Field and Okume Complex.
Algeria: The Corporation has a 49%
interest in a venture with the Algerian national oil company
that is redeveloping three oil fields.
Libya: The Corporation, in conjunction
with its Oasis Group partners, has oil and gas production
operations in the Waha concessions in Libya (Hess 8.16%). The
Corporation also owns a 100% interest in offshore exploration
Area 54, where drilling of an exploration well is planned for
2008.
Gabon: The Corporations
activities in Gabon are conducted through its 77.5% owned
Gabonese subsidiary, where the Corporation has interests in the
Rabi Kounga, Toucan and Atora fields.
Egypt: The Corporation has a
25-year
development lease for the West Med Block 1 concession (West Med
Block) (Hess 55%), which contains four existing natural gas
discoveries and additional exploration opportunities. During
2007, the Corporation commenced front-end engineering and
seismic studies.
Ghana: The Corporation holds an
interest in the Cape Three Points South Block (Hess 100%)
located offshore Ghana where drilling of an exploration well is
planned during 2008.
Asia and
Other
At December 31, 2007, 26% of the Corporations total
proved reserves were located in the Asia and other region (JDA
14%, Indonesia 7%, Thailand 3% and Azerbaijan 2%). During 2007,
7% of the Corporations crude oil and natural gas liquids
production and 44% of its natural gas production were from Asia
and other operations.
Joint Development Area of Malaysia and
Thailand: The Corporation owns an interest in
the JDA (Hess 50%) in the Gulf of Thailand. In the fourth
quarter of 2007, the Corporation completed the expansion of
offshore facilities and installation of wellhead platforms at
the JDA. Full Phase 2 production is expected in the second half
of 2008.
Indonesia: The Corporations
natural gas production in Indonesia primarily comes from its
interests offshore in the Ujung Pangkah project (Hess 75%) and
the Natuna A gas Field (Hess 23%). Natural gas production from
the Ujung Pangkah project commenced in April 2007. In addition,
during 2007 a crude oil development project commenced at Ujung
Pangkah. Production from this Phase 2 oil project is expected to
commence in 2009. The Corporation also owns an interest in the
onshore Jambi Merang natural gas project (Hess 25%), which was
sanctioned for development in 2007.
Thailand: The Corporation has an
interest in the Pailin gas Field (Hess 15%) offshore Thailand.
The Corporation is the operator and owns an interest in the
onshore natural gas project in the Sinphuhorm Block (formerly
the Phu Horm Block) (Hess 35%) which commenced production in the
fourth quarter of 2006.
Azerbaijan: The Corporation has an
interest in the Azeri-Chirag-Gunashli (ACG) fields (Hess 2.72%)
in the Caspian Sea. The Corporation also holds an interest in
the Baku-Tbilisi-Ceyhan (BTC) Pipeline (Hess 2.36%).
Australia: In 2007, the Corporation
acquired a 100% interest in an exploration license covering
780,000 acres in the Carnarvon basin offshore Western
Australia (Block 390-P). During 2008, the Corporation plans
to drill four wells of a 16 well commitment on the block.
During 2007, the Corporation also acquired a 50% interest in
Block 404-P located offshore Western Australia, which
covers a total area of 680,000 acres.
Brazil: The Corporation has interests
in two blocks located offshore Brazil, the BMS-22 Block (Hess
40%) in the Santos Basin, where drilling of an exploration well
is planned in 2008, and the BM-ES-30 Block (Hess 60%) in the
Espirito Santo Basin.
5
Oil and
Gas Reserves
The Corporations net proved oil and gas reserves at the
end of 2007, 2006 and 2005 are presented under Supplementary Oil
and Gas Data on pages 76 through 78 in the accompanying
financial statements.
During 2007, the Corporation provided oil and gas reserve
estimates for 2006 to the United States Department of Energy.
Such estimates are compatible with the information furnished to
the SEC on
Form 10-K
for the year ended December 31, 2006, although not
necessarily directly comparable due to the requirements of the
individual requests. There were no differences in excess of 5%.
Sales commitments: The Corporation has
no contracts or agreements to sell fixed quantities of its crude
oil production. In the United States, natural gas is marketed on
a spot basis and under contracts for varying periods to local
distribution companies, and commercial, industrial and other
purchasers. The Corporations United States natural gas
production is expected to approximate 30% of its 2008 sales
commitments under long-term contracts. The Corporation attempts
to minimize price and supply risks associated with its United
States natural gas supply commitments by entering into purchase
contracts with third parties having reliable sources of supply,
on terms substantially similar to those under its commitments
and by leasing storage facilities.
In international markets, the Corporation generally sells its
natural gas production under long-term sales contracts with
prices that are periodically adjusted due to changes in the
commodity prices or other indices. In the United Kingdom, the
Corporation sells the majority of its natural gas production on
a spot basis.
Average
selling prices and average production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Average selling prices (including the effects of hedging)
(Note A)
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil, including condensate and natural gas liquids (per
barrel)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
64.96
|
|
|
$
|
57.41
|
|
|
$
|
33.86
|
|
Europe
|
|
|
60.76
|
|
|
|
55.80
|
|
|
|
33.30
|
|
Africa
|
|
|
62.04
|
|
|
|
51.18
|
|
|
|
32.10
|
|
Asia and other
|
|
|
72.17
|
|
|
|
61.52
|
|
|
|
54.69
|
|
Worldwide
|
|
|
62.87
|
|
|
|
54.81
|
|
|
|
33.69
|
|
Natural gas (per mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
6.67
|
|
|
$
|
6.59
|
|
|
$
|
7.93
|
|
Europe
|
|
|
6.13
|
|
|
|
6.20
|
|
|
|
5.29
|
|
Asia and other
|
|
|
4.71
|
|
|
|
4.05
|
|
|
|
4.02
|
|
Worldwide
|
|
|
5.60
|
|
|
|
5.50
|
|
|
|
5.65
|
|
Average production (lifting) costs per barrel of oil equivalent
produced (Note B)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
13.56
|
|
|
$
|
9.54
|
|
|
$
|
7.46
|
|
Europe
|
|
|
14.06
|
|
|
|
10.73
|
|
|
|
8.13
|
|
Africa
|
|
|
9.09
|
|
|
|
9.03
|
|
|
|
7.99
|
|
Asia and other
|
|
|
8.41
|
|
|
|
6.54
|
|
|
|
7.29
|
|
Worldwide
|
|
|
11.50
|
|
|
|
9.55
|
|
|
|
7.91
|
|
Note A: Includes inter-company transfers
valued at approximate market prices and the effect of the
Corporations hedging activities.
Note B: Production (lifting) costs consist of
amounts incurred to operate and maintain the Corporations
producing oil and gas wells, related equipment and facilities
(including lease costs of floating production and storage
facilities), transportation costs and production and severance
taxes. Production costs in 2005 exclude Gulf of Mexico hurricane
related expenses. The average production costs per barrel of oil
equivalent reflect the crude oil equivalent of natural gas
production converted on the basis of relative energy content
(six mcf equals one barrel).
The table above does not include costs of finding and developing
proved oil and gas reserves, or the costs of related general and
administrative expenses, interest expense and income taxes.
6
Gross and
net undeveloped acreage at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
Acreage (Note A)
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
(In thousands)
|
|
|
United States
|
|
|
2,497
|
|
|
|
1,701
|
|
Europe
|
|
|
3,862
|
|
|
|
1,356
|
|
Africa
|
|
|
12,357
|
|
|
|
8,850
|
|
Asia and other
|
|
|
15,496
|
|
|
|
10,798
|
|
|
|
|
|
|
|
|
|
|
Total (Note B)
|
|
|
34,212
|
|
|
|
22,705
|
|
|
|
|
|
|
|
|
|
|
Note A: Includes acreage held under
production sharing contracts.
Note B: Licenses covering approximately 32%
of the Corporations net undeveloped acreage held at
December 31, 2007 are scheduled to expire during the next
three years pending the results of exploration activities. These
scheduled expirations are largely in Libya (offshore exploration
Area 54), Algeria and Peru.
Gross and
net developed acreage and productive wells at December 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
|
|
|
|
|
|
|
Acreage
|
|
|
|
|
|
|
|
|
|
Applicable to
|
|
|
Productive Wells (Note A)
|
|
|
|
Productive Wells
|
|
|
Oil
|
|
|
Gas
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
471
|
|
|
|
400
|
|
|
|
731
|
|
|
|
420
|
|
|
|
64
|
|
|
|
50
|
|
Europe
|
|
|
1,618
|
|
|
|
814
|
|
|
|
244
|
|
|
|
86
|
|
|
|
151
|
|
|
|
33
|
|
Africa
|
|
|
9,919
|
|
|
|
958
|
|
|
|
944
|
|
|
|
142
|
|
|
|
|
|
|
|
|
|
Asia and other
|
|
|
2,185
|
|
|
|
624
|
|
|
|
48
|
|
|
|
3
|
|
|
|
235
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
14,193
|
|
|
|
2,796
|
|
|
|
1,967
|
|
|
|
651
|
|
|
|
450
|
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note A: Includes multiple completion wells
(wells producing from different formations in the same bore
hole) totaling 200 gross wells and 39 net wells.
Number of
net exploratory and development wells drilled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exploratory
|
|
|
Net Development
|
|
|
|
Wells
|
|
|
Wells
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Productive wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
54
|
|
|
|
24
|
|
|
|
28
|
|
Europe
|
|
|
3
|
|
|
|
1
|
|
|
|
3
|
|
|
|
14
|
|
|
|
20
|
|
|
|
6
|
|
Africa
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
23
|
|
|
|
17
|
|
|
|
12
|
|
Asia and other
|
|
|
3
|
|
|
|
6
|
|
|
|
1
|
|
|
|
15
|
|
|
|
11
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
8
|
|
|
|
8
|
|
|
|
5
|
|
|
|
106
|
|
|
|
72
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry holes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
1
|
|
|
|
4
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Europe
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Asia and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
3
|
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
11
|
|
|
|
12
|
|
|
|
9
|
|
|
|
106
|
|
|
|
72
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
Number of
wells in process of drilling at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
Wells
|
|
|
Wells
|
|
|
United States
|
|
|
14
|
|
|
|
7
|
|
Europe
|
|
|
6
|
|
|
|
4
|
|
Africa
|
|
|
13
|
|
|
|
6
|
|
Asia and other
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
40
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
Number of
net waterfloods and pressure maintenance projects in process of
installation at December 31, 2007 1
Marketing
and Refining
Total M&R product sales were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007*
|
|
|
2006*
|
|
|
2005*
|
|
|
|
(Thousands of
|
|
|
|
barrels per day)
|
|
|
Gasoline
|
|
|
210
|
|
|
|
218
|
|
|
|
213
|
|
Distillates
|
|
|
147
|
|
|
|
144
|
|
|
|
136
|
|
Residuals
|
|
|
62
|
|
|
|
60
|
|
|
|
64
|
|
Other
|
|
|
32
|
|
|
|
37
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
451
|
|
|
|
459
|
|
|
|
456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Of total refined products sold
in 2007, 2006 and 2005 approximately 50% was obtained from
HOVENSA and Port Reading. The Corporation purchased the balance
from third parties under short-term supply contracts and spot
purchases. |
Refining
The Corporation owns a 50% interest in HOVENSA L.L.C. (HOVENSA),
a refining joint venture in the United States Virgin Islands
with a subsidiary of Petroleos de Venezuela S.A. (PDVSA). In
addition, it owns and operates a refining facility in Port
Reading, New Jersey.
HOVENSA: Refining operations at HOVENSA
consist of crude units, a fluid catalytic cracking unit and a
delayed coker unit.
The following table summarizes capacity and utilization rates
for HOVENSA:
|
|
|
|
|
|
|
|
|
|
|
Refinery
|
|
Refinery Utilization
|
|
|
Capacity
|
|
2007
|
|
2006
|
|
2005
|
|
|
(Thousands of
|
|
|
|
|
|
|
|
|
barrels per day)
|
|
|
|
|
|
|
|
Crude
|
|
500
|
|
90.8%
|
|
89.7%
|
|
92.2%
|
Fluid catalytic cracker
|
|
150
|
|
87.1%
|
|
84.3%
|
|
81.9%
|
Coker
|
|
58
|
|
83.4%
|
|
84.3%
|
|
92.8%
|
The delayed coker unit permits HOVENSA to run lower-cost heavy
crude oil. HOVENSA has a long-term supply contract with PDVSA to
purchase 115,000 barrels per day of Venezuelan Merey heavy
crude oil. PDVSA also supplies 155,000 barrels per day of
Venezuelan Mesa medium gravity crude oil to HOVENSA under a
long-term
crude oil supply contract. The remaining crude oil requirements
are purchased mainly under contracts of one year or less from
third parties and through spot purchases on the open market.
After sales of refined products by HOVENSA to third parties, the
Corporation purchases 50% of HOVENSAs remaining production
at market prices.
8
Gross crude runs at HOVENSA averaged 454,000 barrels per
day in 2007 compared with 448,000 barrels per day in 2006
and 461,000 barrels per day in 2005. During the second
quarter of 2007, the coker unit at HOVENSA was shut down for
approximately 30 days for a scheduled turnaround. The fluid
catalytic cracking unit at HOVENSA was shut down for
approximately 22 days of unscheduled maintenance in 2006.
Port Reading Facility: The Corporation
owns and operates a fluid catalytic cracking facility in Port
Reading, New Jersey, with a capacity of 65,000 barrels per
day. This facility, which processes residual fuel oil and vacuum
gas oil, operated at a rate of approximately 61,000 barrels
per day in 2007 compared with 63,000 barrels per day in
2006 and 55,000 barrels per day in 2005. Substantially all
of Port Readings production is gasoline and heating oil.
Marketing
The Corporation markets refined petroleum products on the East
Coast of the United States to the motoring public, wholesale
distributors, industrial and commercial users, other petroleum
companies, governmental agencies and public utilities. It also
markets natural gas and electricity to utilities and other
industrial and commercial customers.
The Corporation has 1,371
HESS®
gasoline stations at December 31, 2007, including stations
owned by the WilcoHess joint venture (Hess 44%). Approximately
90% of the gasoline stations are operated by the Company or
WilcoHess. Of the operated stations, 93% have convenience stores
on the sites. Most of the Corporations gasoline stations
are in New York, New Jersey, Pennsylvania, Florida,
Massachusetts, North Carolina and South Carolina.
Refined product sales averaged 451,000 barrels per day in
2007 compared with 459,000 barrels per day in 2006 and
456,000 barrels in 2005. Total energy marketing natural gas
sales volumes, including utility and spot sales, were
approximately 1.9 million mcf per day in 2007,
1.8 million mcf per day in 2006 and 1.7 million mcf
per day in 2005. In addition, energy marketing sold electricity
volumes at the rate of 2,800, 1,400 and 500 megawatts (round the
clock) in 2007, 2006 and 2005, respectively.
The Corporation owns 22 terminals with an aggregate storage
capacity of 22 million barrels in its East Coast marketing
areas. The Corporation also owns a terminal in St. Lucia with a
storage capacity of 10 million barrels, which is used for
third party storage.
The Corporation has a 50% voting interest in a consolidated
partnership that trades energy commodities and derivatives. The
Corporation also takes energy commodity and derivative trading
positions for its own account.
The Corporation also has a 92.5% interest in Hess LNG, which is
pursuing investments in liquefied natural gas (LNG) terminals
and related supply, trading and marketing opportunities. The
joint venture is pursuing the development of LNG terminal
projects located in Fall River, Massachusetts and Shannon,
Ireland. The Corporation also has invested in a venture to
develop fuel cells for electricity generation.
Competition
and Market Conditions
See Item 1A, Risk Factors Related to Our Business and
Operations, for a discussion of competition and market
conditions.
Other
Items
Compliance with various existing environmental and pollution
control regulations imposed by federal, state, local and foreign
governments is not expected to have a material adverse effect on
the Corporations earnings and competitive position within
the industry. The Corporation spent $23 million in 2007 for
environmental remediation.
The number of persons employed by the Corporation at year end
was approximately 13,300 in 2007 and 13,700 in 2006.
The Corporations Internet address is www.hess.com. On its
website, the Corporation makes available free of charge its
annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as
reasonably practicable after the Corporation electronically
files with or furnishes such material to the Securities and
Exchange Commission. Copies of the Corporations Code of
Business Conduct and Ethics, its Corporate
9
Governance Guidelines and the charters of the Audit Committee,
the Compensation and Management Development Committee and the
Corporate Governance and Nominating Committee of the Board of
Directors are available on the Corporations website and
are also available free of charge upon request to the Secretary
of the Corporation at its principal executive offices. The
Corporation has also filed with the New York Stock Exchange
(NYSE) its annual certification that the Corporations
chief executive officer is unaware of any violation of the
NYSEs corporate governance standards.
|
|
Item 1A.
|
Risk
Factors Related to Our Business and Operations
|
Our business activities and the value of our securities are
subject to significant risk factors, including those described
below. The risk factors described below could negatively affect
our operations, financial condition, liquidity and results of
operations, and as a result, holders and purchasers of our
securities could lose part or all of their investments. It is
possible additional risks relating to our securities may be
described in a prospectus supplement if we issue securities in
the future.
Commodity Price Risk: Our estimated proved
reserves, revenue, operating cash flows, operating margins,
future earnings and trading operations are highly dependent on
the prices of crude oil, natural gas and refined petroleum
products, which are influenced by numerous factors beyond our
control. Historically these prices have been very volatile. The
major foreign oil producing countries, including members of the
Organization of Petroleum Exporting Countries (OPEC), exert
considerable influence over the supply and price of crude oil
and refined petroleum products. Their ability or inability to
agree on a common policy on rates of production and other
matters has a significant impact on the oil markets. The
commodities trading markets may also influence the selling
prices of crude oil, natural gas and refined petroleum products.
A significant downward trend in commodity prices would have a
material adverse effect on our revenues, profitability and cash
flow and could result in a reduction in the carrying value of
our oil and gas assets, goodwill and proved oil and gas
reserves. To the extent that we engage in hedging activities to
mitigate commodity price volatility, we will not realize the
benefit of price increases above the hedged price.
Technical Risk: We own or have access to a
finite amount of oil and gas reserves which will be depleted
over time. Replacement of oil and gas reserves is subject to
successful exploration drilling, development activities, and
enhanced recovery programs. Therefore, future oil and gas
production is dependent on technical success in finding and
developing additional hydrocarbon reserves. Exploration activity
involves the interpretation of seismic and other geological and
geophysical data, which does not always successfully predict the
presence of commercial quantities of hydrocarbons. Drilling
risks include adverse unexpected conditions, irregularities in
pressure or formations, equipment failure, blowouts and weather
interruptions. Future developments may be affected by unforeseen
reservoir conditions which negatively affect recovery factors or
flow rates. The costs of drilling and development activities
have also been increasing, which could negatively affect
expected economic returns. Although due diligence is used in
evaluating acquired oil and gas properties, similar
uncertainties may be encountered in the production of oil and
gas on properties acquired from others.
Oil and Gas Reserves and Discounted Future Net Cash Flow
Risks: Numerous uncertainties exist in estimating
quantities of proved reserves and future net revenues from those
reserves. Actual future production, oil and gas prices,
revenues, taxes, capital expenditures, operating expenses,
geologic success and quantities of recoverable oil and gas
reserves may vary substantially from those assumed in the
estimates and could materially affect the estimated quantities
and future net revenues of our proved reserves. In addition,
reserve estimates may be subject to downward or upward revisions
based on production performance, purchases or sales of
properties, results of future development, prevailing oil and
gas prices, production sharing contracts which may decrease
reserves as crude oil and natural gas prices increase, and other
factors.
Political Risk: Federal, state, local,
territorial and foreign laws and regulations relating to tax
increases and retroactive tax claims, expropriation of property,
mandatory government participation, cancellation or amendment of
contract rights, and changes in import regulations, as well as
other political developments may affect our operations. Some of
the international areas in which we operate may be politically
less stable than our domestic operations. In addition, the
increasing threat of terrorism around the world poses additional
risks to the operations of the oil and gas industry. In our
M&R segment, we market motor fuels through lessee-dealers
and wholesalers in
10
certain states where legislation prohibits producers or refiners
of crude oil from directly engaging in retail marketing of motor
fuels. Similar legislation has been periodically proposed in the
U.S. Congress and in various other states.
Environmental Risk: Our oil and gas
operations, like those of the industry, are subject to
environmental hazards such as oil spills, produced water spills,
gas leaks and ruptures and discharges of substances or gases
that could expose us to substantial liability for pollution or
other environmental damage. Our operations are also subject to
numerous United States federal, state, local and foreign
environmental laws and regulations. Non-compliance with these
laws and regulations may subject us to administrative, civil or
criminal penalties, remedial
clean-ups
and natural resource damages or other liabilities. In addition,
increasingly stringent environmental regulations, particularly
relating to the production of motor and other fuels and the
potential for controls on greenhouse gas emissions, have
resulted, and will likely continue to result, in higher capital
expenditures and operating expenses for us and the oil and gas
industry in general.
Competitive Risk: The petroleum industry is
highly competitive and very capital intensive. We encounter
competition from numerous companies in each of our activities,
including acquiring rights to explore for crude oil and natural
gas, and in purchasing and marketing of refined products and
natural gas. Many competitors, including national oil companies,
are larger and have substantially greater resources. We are also
in competition with producers and marketers of other forms of
energy. Increased competition for worldwide oil and gas assets
has significantly increased the cost of acquisitions. In
addition, competition for drilling services, technical expertise
and equipment has affected the availability of technical
personnel and drilling rigs and has increased capital and
operating costs.
Catastrophic Risk: Although we maintain a
level of insurance coverage consistent with industry practices
against property and casualty losses, our oil and gas operations
are subject to unforeseen occurrences which may damage or
destroy assets or interrupt operations. Examples of catastrophic
risks include hurricanes, fires, explosions and blowouts. These
occurrences have affected us from time to time. During 2005, our
annual Gulf of Mexico production of crude oil and natural gas
was reduced by 7,000 barrels of oil equivalent per day
(boepd) due to the impact of Hurricanes Katrina and Rita.
|
|
Item 3.
|
Legal
Proceedings
|
The Registrant, along with many other companies engaged in
refining and marketing of gasoline, has been a party to lawsuits
and claims related to the use of methyl tertiary butyl ether
(MTBE) in gasoline. A series of substantially identical
lawsuits, many involving water utilities or governmental
entities, were filed in jurisdictions across the United States
against producers of MTBE and petroleum refiners who produce
gasoline containing MTBE, including the Registrant. These cases
have been consolidated in the Southern District of New York and,
as of the end of 2007, the Registrant is named as a defendant in
51 of approximately 80 cases pending. The principal allegation
in all cases is that gasoline containing MTBE is a defective
product and that these parties are strictly liable in proportion
to their share of the gasoline market for damage to groundwater
resources and are required to take remedial action to ameliorate
the alleged effects on the environment of releases of MTBE. The
damages claimed in these actions are substantial and in some
cases, punitive damages are also sought. In April 2005, the
District Court denied the primary legal aspects of the
defendants motion to dismiss these actions. As a result of
Court-ordered mediation, the Registrant anticipates that
settlement will be reached in a number of the pending cases, the
number and terms of which are currently being negotiated and are
subject to a confidentiality agreement. In the fourth quarter
2007, the Registrant recorded a pre-tax charge of
$40 million related to MTBE litigation.
Over the last several years, many refiners have entered into
consent agreements to resolve the United States Environmental
Protection Agencys (EPA) assertions that refining
facilities were modified or expanded without complying with New
Source Review regulations that require permits and new emission
controls in certain circumstances and other regulations that
impose emissions control requirements. These consent agreements,
which arise out of an EPA enforcement initiative focusing on
petroleum refiners and utilities, have typically imposed
substantial civil fines and penalties and required
(i) significant capital expenditures to install emissions
control equipment over a three to eight year time period and
(ii) changes to operations which resulted in increased
operating costs. The capital expenditures, penalties and
supplemental environmental projects for individual
11
refineries covered by the settlements can vary significantly,
depending on the size and configuration of the refinery, the
circumstances of the alleged modifications and whether the
refinery has previously installed more advanced pollution
controls. EPA initially contacted Registrant and HOVENSA L.L.C.
(HOVENSA), its 50% owned joint venture with Petroleos de
Venezuela, which owns and operates a refinery in the
U.S. Virgin Islands, regarding the Petroleum Refinery
Initiative in August 2003 and discussions resumed in August
2005. The Registrant and HOVENSA have had and expect to have
further discussions with the EPA regarding the Petroleum
Refining Initiative, although both the Registrant and HOVENSA
have already installed many of the pollution controls required
of other refiners under the consent agreements. While the effect
on the Corporation of the Petroleum Refining Initiative cannot
be estimated at this time, additional future capital
expenditures and operating expenses may be incurred. The amount
of penalties, if any, is not expected to be material to the
Corporation. Negotiations with EPA are continuing and
substantial progress has been made toward resolving this matter.
On September 13, 2007, HOVENSA received a Notice Of
Violation (NOV) pursuant to section 113(a)(i) of the Clean
Air Act (Act) from the United States Environmental Protection
Agency (EPA) finding that HOVENSA failed to obtain proper
permitting for the construction and operation of its delayed
coking unit in accordance with applicable law and regulations.
HOVENSA believes it properly obtained all necessary permits for
this project. The NOV states that EPA has authority to issue an
administrative order assessing penalties for violation of the
Act. However, HOVENSA intends to enter into discussions with the
EPA to reach resolution of this matter. Registrant does not
believe that this matter will result in material liability to
HOVENSA or Registrant.
In December 2006, HOVENSA received a NOV from the EPA alleging
non-compliance with emissions limits in a permit issued by the
Virgin Islands Department of Planning and Natural Resources
(DPNR) for the two process heaters in the delayed coking unit.
The NOV was issued in response to a voluntary investigation and
submission by HOVENSA regarding potential non-compliance with
the permit emissions limits for two pollutants. Any exceedances
were minor from the perspective of the amount of pollutants
emitted in excess of the limits. HOVENSA intends to work with
the appropriate governmental agency to reach resolution of this
matter and does not believe that it will result in material
liability.
Registrant is one of over 60 companies that have received a
directive from the New Jersey Department of Environmental
Protection (NJDEP) to remediate contamination in the sediments
of the lower Passaic River and NJDEP is also seeking natural
resource damages. The directive, insofar as it affects
Registrant, relates to alleged releases from a petroleum bulk
storage terminal in Newark, New Jersey now owned by the
Registrant. Registrant and over 40 companies entered into
an Administrative Order on Consent with EPA to study the same
contamination. In June 2007, EPA issued a draft study which
evaluated six alternatives for early action, with costs ranging
from $900 million to $2.3 billion. Based on adverse
comments from Registrant and others, EPA is reevaluating its
alternatives. In addition, the federal trustees for natural
resources have begun a separate assessment of damages to natural
resources in the Passaic River. Given the ongoing studies,
remedial costs cannot be reliably estimated at this time. Based
on currently known facts and circumstances, the Registrant does
not believe that this matter will result in material liability
because its terminal could not have contributed contamination
along most of the rivers length and did not store or use
contaminants which are of the greatest concern in the river
sediments, and because there are numerous other parties who will
likely share in the cost of remediation and damages.
In July 2004, Hess Oil Virgin Islands Corp. (HOVIC), a wholly
owned subsidiary of the Registrant, and HOVENSA, each received a
letter from the Commissioner of the Virgin Islands Department of
Planning and Natural Resources and Natural Resources Trustees,
advising of the Trustees intention to bring suit against
HOVIC and HOVENSA under the Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA). The letter
alleges that HOVIC and HOVENSA are potentially responsible for
damages to natural resources arising from releases of hazardous
substances from the HOVENSA Oil Refinery. HOVENSA
currently owns and operates a petroleum refinery on the south
shore of St. Croix, United States Virgin Islands, which had
been operated by HOVIC until October 1998. An action was filed
on May 5, 2005 in the District Court of the Virgin Islands
against HOVENSA, HOVIC and other companies that operated
industrial facilities on the south shore of St. Croix
asserting that the defendants are liable under CERCLA and
territorial statutory and common law for damages to natural
resources. HOVIC and HOVENSA do not believe that this matter
will result in a material liability as they believe that they
have strong defenses to this complaint, and they intend to
vigorously defend this matter.
12
Registrant has been served with a complaint from the New York
State Department of Environmental Conservation (DEC) relating to
alleged violations at its petroleum terminal in Brooklyn, New
York. The complaint, which seeks an order to shut down the
terminal and penalties in unspecified amounts, alleges
violations involving the structural integrity of certain tanks,
the erosion of shorelines and bulkheads, petroleum discharges
and improper certification of tank repairs. DEC is also seeking
relief relating to remediation of certain gasoline stations in
the New York metropolitan area. Registrant and DEC have reached
a settlement in principle, which is expected to be finalized in
early 2008. Any settlement is not expected to be material to the
Corporation.
The Registrant periodically receives notices from EPA that it is
a potential responsible party under the Superfund
legislation with respect to various waste disposal sites. Under
this legislation, all potentially responsible parties are
jointly and severally liable. For certain sites, EPAs
claims or assertions of liability against the Corporation
relating to these sites have not been fully developed. With
respect to the remaining sites, EPAs claims have been
settled, or a proposed settlement is under consideration, in all
cases for amounts that are not material. The ultimate impact of
these proceedings, and of any related proceedings by private
parties, on the business or accounts of the Corporation cannot
be predicted at this time due to the large number of other
potentially responsible parties and the speculative nature of
clean-up
cost estimates, but is not expected to be material.
The Securities and Exchange Commission (SEC) has notified the
Registrant that on July 21, 2005, it commenced a private
investigation into payments made to the government of Equatorial
Guinea or to officials and persons affiliated with officials of
the government of Equatorial Guinea. The staff of the SEC has
requested documents and information from the Registrant and
other oil and gas companies that have operations or interests in
Equatorial Guinea. The staff of the SEC had previously been
conducting an informal inquiry into such matters. The Registrant
has been cooperating and continues to cooperate with the SEC
investigation.
The Corporation is from time to time involved in other judicial
and administrative proceedings, including proceedings relating
to other environmental matters. Although the ultimate outcome of
these proceedings cannot be ascertained at this time and some of
them may be resolved adversely to the Corporation, no such
proceeding is required to be disclosed under applicable rules of
the Securities and Exchange Commission. In managements
opinion, based upon currently known facts and circumstances,
such proceedings in the aggregate will not have a material
adverse effect on the financial condition of the Corporation.
13
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
During the fourth quarter of 2007, no matter was submitted to a
vote of security holders through the solicitation of proxies or
otherwise.
Executive
Officers of the Registrant
The following table presents information as of February 1,
2008 regarding executive officers of the Registrant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Individual
|
|
|
|
|
|
|
Became an
|
|
|
|
|
|
|
Executive
|
Name
|
|
Age
|
|
Office Held*
|
|
Officer
|
|
John B. Hess
|
|
|
53
|
|
|
Chairman of the Board, Chief Executive Officer and Director
|
|
|
1983
|
|
J. Barclay Collins II
|
|
|
63
|
|
|
Executive Vice President, General Counsel and Director
|
|
|
1986
|
|
John J. OConnor
|
|
|
61
|
|
|
Executive Vice President, President of Worldwide Exploration and
Production and Director
|
|
|
2001
|
|
F. Borden Walker
|
|
|
54
|
|
|
Executive Vice President and President of Marketing and Refining
and Director
|
|
|
1996
|
|
Brian J. Bohling
|
|
|
47
|
|
|
Senior Vice President
|
|
|
2004
|
|
William T. Drennen
|
|
|
57
|
|
|
Senior Vice President
|
|
|
2007
|
|
John A. Gartman
|
|
|
60
|
|
|
Senior Vice President
|
|
|
1997
|
|
Scott Heck
|
|
|
50
|
|
|
Senior Vice President
|
|
|
2005
|
|
Lawrence H. Ornstein
|
|
|
56
|
|
|
Senior Vice President
|
|
|
1995
|
|
Howard Paver
|
|
|
57
|
|
|
Senior Vice President
|
|
|
2002
|
|
John P. Rielly
|
|
|
45
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
2002
|
|
George F. Sandison
|
|
|
51
|
|
|
Senior Vice President
|
|
|
2003
|
|
John J. Scelfo
|
|
|
50
|
|
|
Senior Vice President
|
|
|
2004
|
|
Gordon Shearer
|
|
|
53
|
|
|
Senior Vice President
|
|
|
2007
|
|
John V. Simon
|
|
|
54
|
|
|
Senior Vice President
|
|
|
2007
|
|
Robert J. Vogel
|
|
|
48
|
|
|
Vice President & Treasurer
|
|
|
2004
|
|
|
|
|
* |
|
All officers referred to herein
hold office in accordance with the By-Laws until the first
meeting of the Directors following the annual meeting of
stockholders of the Registrant and until their successors shall
have been duly chosen and qualified. Each of said officers was
elected to the office set forth opposite his name on May 2,
2007, except for Mr. Drennen, who was elected on
July 2, 2007. The first meeting of Directors following the
next annual meeting of stockholders of the Registrant is
scheduled to be held May 7, 2008. |
Except for Messrs. Bohling, Drennen, Sandison, Scelfo and
Shearer, each of the above officers has been employed by the
Registrant or its subsidiaries in various managerial and
executive capacities for more than five years. Mr. Bohling
was employed in senior human resource positions with American
Standard Corporation and CDI Corporation before joining the
Registrant in 2004. Mr. Drennen served in senior executive
positions in exploration and technology at ExxonMobil and its
subsidiaries prior to joining the company in 2007.
Mr. Scelfo was chief financial officer of Sirius Satellite
Radio and a division of Dell Computer before his employment by
the Registrant in 2003. Mr. Sandison served in senior
executive positions in the area of global drilling with Texaco,
Inc. before he was employed by the Registrant in 2003. Prior to
joining Hess LNG, a joint venture subsidiary of the company, in
2004, Mr. Shearer was a consultant at Poten Partners, and
held other senior positions in the liquefied natural gas
industry.
14
PART II
|
|
Item 5.
|
Market
for the Registrants Common Stock, Related Stockholder
Matters and Issuer Purchases of Equity Securities
|
Stock
Market Information
The common stock of Hess Corporation is traded principally on
the New York Stock Exchange (ticker symbol: HES). High and low
sales prices were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
Quarter Ended
|
|
High
|
|
|
Low
|
|
|
High
|
|
|
Low
|
|
March 31
|
|
$
|
58.00
|
|
|
$
|
45.96
|
|
|
$
|
52.00
|
|
|
$
|
42.83
|
|
June 30
|
|
|
61.48
|
|
|
|
54.55
|
|
|
|
53.46
|
|
|
|
43.23
|
|
September 30
|
|
|
69.87
|
|
|
|
53.12
|
|
|
|
56.45
|
|
|
|
38.30
|
|
December 31
|
|
|
105.85
|
|
|
|
63.58
|
|
|
|
52.70
|
|
|
|
37.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
Graph
Set forth below is a line graph comparing the cumulative total
shareholder return, assuming reinvestment of dividends, on the
Corporations common stock with the cumulative total
return, assuming reinvestment of dividends, of:
|
|
|
|
|
Standard & Poors 500 Stock Index, which includes
the Corporation, and
|
|
|
|
AMEX Oil Index, which is comprised of companies involved in
various phases of the oil industry including the Corporation.
|
As of each December 31, over a five-year period commencing
on December 31, 2002 and ending on December 31, 2007:
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
Holders
At December 31, 2007, there were 5,673 stockholders (based
on number of holders of record) who owned a total of
320,599,585 shares of common stock.
15
Dividends
Cash dividends on common stock totaled $.40 per share ($.10 per
quarter) during 2007 and 2006 on a split adjusted basis.
Equity
Compensation Plans
Following is information on the Registrants equity
compensation plans at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Securities
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
|
|
|
Available for
|
|
|
|
Number of
|
|
|
|
|
|
Future Issuance
|
|
|
|
Securities to
|
|
|
Weighted
|
|
|
Under Equity
|
|
|
|
be Issued
|
|
|
Average
|
|
|
Compensation
|
|
|
|
Upon Exercise
|
|
|
Exercise Price
|
|
|
Plans
|
|
|
|
of Outstanding
|
|
|
of Outstanding
|
|
|
(Excluding
|
|
|
|
Options,
|
|
|
Options,
|
|
|
Securities
|
|
|
|
Warrants and
|
|
|
Warrants and
|
|
|
Reflected in
|
|
|
|
Rights
|
|
|
Rights
|
|
|
Column (a))
|
|
Plan Category
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity compensation plans approved by security holders
|
|
|
11,292,000
|
|
|
$
|
38.31
|
|
|
|
7,821,000
|
*
|
Equity compensation plans not approved by security holders**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
These securities may be awarded
as stock options, restricted stock or other awards permitted
under the Registrants equity compensation plan. |
|
** |
|
Registrant has a Stock Award
Program pursuant to which each non-employee director receives
$150,000 in value of Registrants common stock each year.
These awards are made from shares purchased by the Company in
the open market. Stockholders did not approve this equity
compensation plan. |
See Note 8, Share-Based Compensation, in the
notes to the financial statements for further discussion of the
Corporations equity compensation plans.
16
|
|
Item 6.
|
Selected
Financial Data
|
A five-year summary of selected financial data follows*:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Millions of dollars, except per share amounts)
|
|
|
Sales and other operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids
|
|
$
|
6,303
|
|
|
$
|
5,307
|
|
|
$
|
3,219
|
|
|
$
|
2,594
|
|
|
$
|
2,295
|
|
Natural gas (including sales of purchased gas)
|
|
|
6,877
|
|
|
|
6,826
|
|
|
|
6,423
|
|
|
|
4,638
|
|
|
|
4,522
|
|
Refined and other energy products
|
|
|
17,063
|
|
|
|
14,411
|
|
|
|
11,690
|
|
|
|
8,125
|
|
|
|
6,250
|
|
Convenience store sales and other operating revenues
|
|
|
1,404
|
|
|
|
1,523
|
|
|
|
1,415
|
|
|
|
1,376
|
|
|
|
1,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
31,647
|
|
|
$
|
28,067
|
|
|
$
|
22,747
|
|
|
$
|
16,733
|
|
|
$
|
14,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1,832
|
(a)
|
|
$
|
1,920
|
(b)
|
|
$
|
1,226
|
(c)
|
|
$
|
970
|
(d)
|
|
$
|
467
|
(e)
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
169
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,832
|
|
|
$
|
1,920
|
|
|
$
|
1,226
|
|
|
$
|
977
|
|
|
$
|
643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less preferred stock dividends
|
|
|
|
|
|
|
44
|
|
|
|
48
|
|
|
|
48
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common shareholders
|
|
$
|
1,832
|
|
|
$
|
1,876
|
|
|
$
|
1,178
|
|
|
$
|
929
|
|
|
$
|
638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
5.86
|
|
|
$
|
6.75
|
|
|
$
|
4.32
|
|
|
$
|
3.43
|
|
|
$
|
1.74
|
|
Net income
|
|
|
5.86
|
|
|
|
6.75
|
|
|
|
4.32
|
|
|
|
3.46
|
|
|
|
2.40
|
|
Diluted earnings per share**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
5.74
|
|
|
$
|
6.08
|
|
|
$
|
3.93
|
|
|
$
|
3.17
|
|
|
$
|
1.72
|
|
Net income
|
|
|
5.74
|
|
|
|
6.08
|
|
|
|
3.93
|
|
|
|
3.19
|
|
|
|
2.37
|
|
Total assets
|
|
$
|
26,131
|
|
|
$
|
22,442
|
|
|
$
|
19,158
|
|
|
$
|
16,312
|
|
|
$
|
13,983
|
|
Total debt
|
|
|
3,980
|
|
|
|
3,772
|
|
|
|
3,785
|
|
|
|
3,835
|
|
|
|
3,941
|
|
Stockholders equity
|
|
|
9,774
|
|
|
|
8,147
|
|
|
|
6,318
|
|
|
|
5,597
|
|
|
|
5,340
|
|
Dividends per share of common stock**
|
|
$
|
.40
|
|
|
$
|
.40
|
|
|
$
|
.40
|
|
|
$
|
.40
|
|
|
$
|
.40
|
|
|
|
|
* |
|
The financial results for 2007,
2006 and 2005 reflect the impact of FASB Staff Position AUG
AIR-1,Accounting for Planned Major Maintenance
Activities which was retrospectively adopted from
January 1, 2005. If the Corporation had adopted this
standard on January 1, 2003, after-tax net income would
have decreased by $8 million in 2004 and increased by
$18 million in 2003. |
|
** |
|
Per share amounts in all periods
reflect the
3-for-1
stock split on May 31, 2006. |
|
(a) |
|
Includes net after-tax expenses
of $75 million primarily relating to asset impairments,
estimated production imbalance settlements and a charge for MTBE
litigation, partially offset by income from LIFO inventory
liquidations and gains from asset sales. |
|
(b) |
|
Includes net after-tax income of
$173 million primarily from sales of assets, partially
offset by income tax adjustments and accrued leased office
closing costs. |
|
(c) |
|
Includes after-tax expenses of
$37 million primarily relating to income taxes on
repatriated earnings, premiums on bond repurchases and hurricane
related expenses, partially offset by gains from asset sales and
a LIFO inventory liquidation. |
|
(d) |
|
Includes net after-tax income of
$76 million primarily from sales of assets and income tax
adjustments. |
|
(e) |
|
Includes net after-tax expenses
of $25 million, principally from premiums on bond
repurchases and accrued severance and leased office closing
costs, partially offset by income tax adjustments and asset
sales. |
17
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Overview
The Corporation is a global integrated energy company that
operates in two segments, Exploration and Production (E&P)
and Marketing and Refining (M&R). The E&P segment
explores for, develops, produces, purchases, transports and
sells crude oil and natural gas. The M&R segment
manufactures, purchases, transports, trades and markets refined
petroleum products, natural gas and electricity.
Net income in 2007 was $1,832 million compared with
$1,920 million in 2006 and $1,226 million in 2005.
Diluted earnings per share were $5.74 in 2007 compared with
$6.08 in 2006 and $3.93 in 2005. A table of items affecting
comparability between periods is shown on page 21.
Exploration
and Production
The Corporations strategy for the E&P segment is to
profitably grow reserves and production in a sustainable and
financially disciplined manner. The Corporations total
proved reserves were 1,330 million barrels of oil
equivalent (boe) at December 31, 2007 compared with
1,243 million boe at December 31, 2006 and
1,093 million boe at December 31, 2005. Total proved
reserves at year end 2007 increased 87 million boe or 7%
from the end of 2006.
E&P net income was $1,842 million in 2007,
$1,763 million in 2006 and $1,058 million in 2005. The
improved results in 2007 as compared to 2006 were primarily
driven by higher average crude oil selling prices and increased
crude oil and natural gas production. See further discussion in
Comparison of Results on page 21.
Production averaged 377,000 barrels of oil equivalent per
day (boepd) in 2007 compared with 359,000 boepd in 2006 and
335,000 boepd in 2005. Production in 2007 increased 18,000 boepd
or 5% from 2006 reflecting the following developments:
|
|
|
|
|
The Okume Complex in Equatorial Guinea (Hess 85%), which
commenced production in December 2006, exhibited strong
reservoir performance and facilities uptime during the year. In
January 2008, production reached design capacity of 60,000
boepd, gross (approximately 40,000 boepd, net).
|
|
|
|
The Ujung Pangkah Field (Hess 75%) in Indonesia commenced
natural gas production in April 2007. The Corporations net
share of production from the field ramped up to an average of
69,000 mcf per day in the fourth quarter of 2007.
|
|
|
|
The Atlantic (Hess 25%) and Cromarty (Hess 90%) natural gas
fields in the United Kingdom North Sea, which came onstream in
June 2006, contributed to the Corporations year-over-year
production growth. Production from the Cromarty Field was shut
in during the summer when natural gas prices were seasonally
lower and then full production re-commenced in October at higher
prices.
|
|
|
|
The Corporation benefited from a full year of natural gas
production from Sinphuhorm (Hess 35%) located onshore Thailand,
which commenced production in the fourth quarter of 2006, and
from production growth in Azerbaijan and Russia.
|
|
|
|
The Snohvit Field located offshore Norway (Hess 3.26%) commenced
natural gas production in September 2007 and the Genghis Khan
Field in the Gulf of Mexico (Hess 28%) started crude oil
production in October 2007.
|
In 2008, the Corporation expects total worldwide production of
approximately 380,000 boepd to 390,000 boepd.
During the year, the Corporation progressed development projects
that will add to its production in future years:
|
|
|
|
|
The expansion of offshore facilities and installation of
wellhead platforms was completed in the fourth quarter at Block
A-18 of the
Joint Development Area of Malaysia and Thailand (JDA) (Hess
50%). Full Phase 2 production is expected in the second half of
2008.
|
18
|
|
|
|
|
The Shenzi development (Hess 28%) in the deepwater Gulf of
Mexico progressed with the installation of tension leg platform
tendon piles and hull fabrication. First production is expected
to commence in
mid-2009.
|
|
|
|
Development of the residual oil zone at the
Seminole-San Andres Unit (Hess 34.3%) in the Permian Basin
commenced and is advancing as planned. Production is expected to
start up in 2009.
|
|
|
|
Development of the Ujung Pangkah crude oil project commenced and
facilities engineering and construction continue on schedule.
Production from this Phase 2 oil project is expected to commence
in 2009.
|
|
|
|
The Jambi Merang natural gas project (Hess 25%) in Indonesia was
sanctioned during the year.
|
During 2007, the Corporations exploration activities
included:
|
|
|
|
|
The Corporation gained access to new exploration acreage
including two offshore blocks on the Australian Northwest Shelf,
licenses WA-390-P (Hess 100%) and nearby WA-404-P (Hess 50%)
with total gross acreage of approximately 1.5 million
acres. Additionally, more than 125,000 net undeveloped acres
were added in the Bakken trend of North Dakota.
|
|
|
|
On the Pony prospect on Green Canyon Block 468 (Hess 100%)
in the deepwater Gulf of Mexico a sidetrack from the original
discovery well was successfully completed in the first quarter
and a second appraisal well is being drilled about
1.5 miles northwest of the original discovery well.
|
|
|
|
At the Tubular Bells discovery (Hess 20%) on Mississippi Canyon
Block 682 in the deepwater Gulf of Mexico a successful
sidetrack well was completed during the first quarter of 2007
and a further appraisal well was spud in October 2007.
|
During 2007, the Corporation completed the following acquisition
and divestiture transactions:
|
|
|
|
|
In February 2007, the Corporation completed the acquisition of a
28% interest in the Genghis Khan oil and gas development located
in the deepwater Gulf of Mexico on Green Canyon Blocks 652
and 608, which is part of the same geological structure as the
Shenzi development.
|
|
|
|
In the second quarter, interests in the Scott-Telford fields
located offshore United Kingdom were sold for $93 million
resulting in an after-tax gain of $15 million
($21 million before income taxes). The Corporations
share of production from the Scott-Telford fields was
approximately 6,500 boepd at the time of sale.
|
Marketing
and Refining
The Corporations strategy for the M&R segment is to
deliver consistent operating performance and generate free cash
flow. M&R net income was $300 million in 2007,
$394 million in 2006 and $499 million in 2005.
Profitability in 2007 and 2006 was adversely affected by lower
average margins.
Refining operations contributed net income of $193 million
in 2007, $240 million in 2006 and $330 million in
2005. The Corporation received cash distributions from HOVENSA,
a 50% owned refining joint venture with a subsidiary of
Petroleos de Venezuela S.A. (PDVSA), totaling $300 million
in 2007, $400 million in 2006 and $275 million in
2005. Gross crude runs at HOVENSA averaged 454,000 barrels
per day in 2007 compared with 448,000 barrels per day in
2006 and 461,000 barrels per day in 2005. In 2007, HOVENSA
successfully completed the first turnaround of its delayed
coking unit. The Port Reading refinery operated at an average of
61,000 barrels per day in 2007 versus 63,000 barrels
per day in 2006 and 55,000 barrels per day in 2005.
Marketing earnings were $83 million in 2007,
$108 million in 2006 and $136 million in 2005. Total
refined product sales volumes averaged 451,000 barrels per
day in 2007 compared with 459,000 barrels per day in 2006
and 456,000 barrels per day in 2005.
Liquidity
and Capital and Exploratory Expenditures
Net cash provided by operating activities was
$3,507 million in 2007, $3,491 million in 2006 and
$1,840 million in 2005, principally reflecting increasing
earnings. At December 31, 2007, cash and cash equivalents
totaled $607 million compared with $383 million at
December 31, 2006. Total debt was
19
$3,980 million at December 31, 2007 compared with
$3,772 million at December 31, 2006. The
Corporations debt to capitalization ratio at
December 31, 2007 was 28.9% compared with 31.6% at the end
of 2006. The Corporation has debt maturities of $62 million
in 2008 and $143 million in 2009.
Capital and exploratory expenditures were as follows for the
years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
1,603
|
|
|
$
|
908
|
|
International
|
|
|
2,183
|
|
|
|
2,979
|
|
|
|
|
|
|
|
|
|
|
Total Exploration and Production
|
|
|
3,786
|
|
|
|
3,887
|
|
Marketing, Refining and Corporate
|
|
|
140
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
Total Capital and Exploratory Expenditures
|
|
$
|
3,926
|
|
|
$
|
4,056
|
|
|
|
|
|
|
|
|
|
|
Exploration expenses charged to income included above:
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
192
|
|
|
$
|
110
|
|
International
|
|
|
156
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
Total exploration expenses charged to income included above
|
|
$
|
348
|
|
|
$
|
212
|
|
|
|
|
|
|
|
|
|
|
|
The Corporation anticipates $4.4 billion in capital and
exploratory expenditures in 2008, of which $4.3 billion
relates to E&P operations.
Consolidated
Results of Operations
The after-tax results by major operating activity are summarized
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars,
|
|
|
|
except per share data)
|
|
|
Exploration and Production
|
|
$
|
1,842
|
|
|
$
|
1,763
|
|
|
$
|
1,058
|
|
Marketing and Refining
|
|
|
300
|
|
|
|
394
|
|
|
|
499
|
|
Corporate
|
|
|
(150
|
)
|
|
|
(110
|
)
|
|
|
(191
|
)
|
Interest expense
|
|
|
(160
|
)
|
|
|
(127
|
)
|
|
|
(140
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,832
|
|
|
$
|
1,920
|
|
|
$
|
1,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share diluted
|
|
$
|
5.74
|
|
|
$
|
6.08
|
|
|
$
|
3.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In the discussion that follows, the financial effects of certain
transactions are disclosed on an after-tax basis. Management
reviews segment earnings on an after-tax basis and uses
after-tax amounts in its review of variances in segment
earnings. Management believes that after-tax amounts are a
preferable method of explaining variances in earnings, since
they show the entire effect of a transaction rather than only
the pre-tax amount. After-tax amounts are determined by applying
the income tax rate in each tax jurisdiction to pre-tax amounts.
20
The following items of income (expense), on an after-tax basis,
are included in net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains from asset sales
|
|
$
|
15
|
|
|
$
|
236
|
|
|
$
|
41
|
|
Asset impairments
|
|
|
(56
|
)
|
|
|
|
|
|
|
|
|
Estimated production imbalance settlements
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
Income tax adjustments
|
|
|
|
|
|
|
(45
|
)
|
|
|
11
|
|
Accrued office closing costs
|
|
|
|
|
|
|
(18
|
)
|
|
|
|
|
Hurricane related costs
|
|
|
|
|
|
|
|
|
|
|
(26
|
)
|
Legal settlement
|
|
|
|
|
|
|
|
|
|
|
11
|
|
Marketing and Refining
|
|
|
|
|
|
|
|
|
|
|
|
|
LIFO inventory liquidations
|
|
|
24
|
|
|
|
|
|
|
|
32
|
|
Charge related to customer bankruptcy
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated MTBE litigation
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
Tax on repatriated earnings
|
|
|
|
|
|
|
|
|
|
|
(72
|
)
|
Premiums on bond repurchases
|
|
|
|
|
|
|
|
|
|
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(75
|
)
|
|
$
|
173
|
|
|
$
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The items in the table above are explained, and the pre-tax
amounts are shown, on pages 24 through 27.
Comparison
of Results
Exploration
and Production
Following is a summarized income statement of the
Corporations Exploration and Production operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Sales and other operating revenues*
|
|
$
|
7,498
|
|
|
$
|
6,524
|
|
|
$
|
4,210
|
|
Other income
|
|
|
65
|
|
|
|
428
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
7,563
|
|
|
|
6,952
|
|
|
|
4,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses, including related taxes
|
|
|
1,581
|
|
|
|
1,250
|
|
|
|
1,007
|
|
Exploration expenses, including dry holes and lease impairment
|
|
|
515
|
|
|
|
552
|
|
|
|
397
|
|
General, administrative and other expenses
|
|
|
257
|
|
|
|
209
|
|
|
|
140
|
|
Depreciation, depletion and amortization
|
|
|
1,503
|
|
|
|
1,159
|
|
|
|
965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
3,856
|
|
|
|
3,170
|
|
|
|
2,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations from continuing operations before income
taxes
|
|
|
3,707
|
|
|
|
3,782
|
|
|
|
1,795
|
|
Provision for income taxes
|
|
|
1,865
|
|
|
|
2,019
|
|
|
|
737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
1,842
|
|
|
$
|
1,763
|
|
|
$
|
1,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Amounts differ from E&P
operating revenues in Note 16 Segment
Information primarily due to the exclusion of sales of
hydrocarbons purchased from third parties. |
21
After considering the Exploration and Production items in the
table on page 21, the remaining changes in Exploration and
Production earnings are primarily attributable to changes in
selling prices, production volumes, operating costs, exploration
expenses and income taxes, as discussed below.
Selling prices: Higher average selling
prices, primarily crude oil, increased Exploration and
Production revenues by approximately $740 million in 2007
compared with 2006. In 2006, the increase in average crude oil
selling prices and reduced hedge positions increased revenues by
approximately $1,900 million compared with 2005.
The Corporations average selling prices were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Crude oil-per barrel (including hedging)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
69.23
|
|
|
$
|
60.45
|
|
|
$
|
32.64
|
|
Europe
|
|
|
60.99
|
|
|
|
56.19
|
|
|
|
33.13
|
|
Africa
|
|
|
62.04
|
|
|
|
51.18
|
|
|
|
32.10
|
|
Asia and other
|
|
|
72.17
|
|
|
|
61.52
|
|
|
|
54.71
|
|
Worldwide
|
|
|
63.44
|
|
|
|
55.31
|
|
|
|
33.38
|
|
Crude oil-per barrel (excluding hedging)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
69.23
|
|
|
$
|
60.45
|
|
|
$
|
51.16
|
|
Europe
|
|
|
60.99
|
|
|
|
58.46
|
|
|
|
52.22
|
|
Africa
|
|
|
71.71
|
|
|
|
62.80
|
|
|
|
51.70
|
|
Asia and other
|
|
|
72.17
|
|
|
|
61.52
|
|
|
|
54.71
|
|
Worldwide
|
|
|
67.79
|
|
|
|
60.41
|
|
|
|
51.94
|
|
Natural gas liquids-per barrel
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
51.89
|
|
|
$
|
46.22
|
|
|
$
|
38.50
|
|
Europe
|
|
|
57.20
|
|
|
|
47.30
|
|
|
|
37.13
|
|
Worldwide
|
|
|
53.72
|
|
|
|
46.59
|
|
|
|
38.08
|
|
Natural gas-per mcf
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
6.67
|
|
|
$
|
6.59
|
|
|
$
|
7.93
|
|
Europe
|
|
|
6.13
|
|
|
|
6.20
|
|
|
|
5.29
|
|
Asia and other
|
|
|
4.71
|
|
|
|
4.05
|
|
|
|
4.02
|
|
Worldwide
|
|
|
5.60
|
|
|
|
5.50
|
|
|
|
5.65
|
|
The after-tax impacts of hedging reduced earnings by
$244 million ($399 million before income taxes) in
2007, $285 million ($449 million before income taxes)
in 2006 and $989 million ($1,582 million before income
taxes) in 2005.
Production and sales volumes: The
Corporations crude oil and natural gas production was
377,000 boepd in 2007 compared with 359,000 boepd in 2006 and
335,000 boepd in 2005. The Corporation anticipates that its 2008
production will average between 380,000 and 390,000 boepd.
22
The Corporations net daily worldwide production was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Crude oil (thousands of barrels per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
31
|
|
|
|
36
|
|
|
|
44
|
|
Europe
|
|
|
93
|
|
|
|
109
|
|
|
|
110
|
|
Africa
|
|
|
115
|
|
|
|
85
|
|
|
|
67
|
|
Asia and other
|
|
|
21
|
|
|
|
12
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
260
|
|
|
|
242
|
|
|
|
228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids (thousands of barrels per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
10
|
|
|
|
10
|
|
|
|
12
|
|
Europe
|
|
|
5
|
|
|
|
5
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
15
|
|
|
|
15
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (thousands of mcf per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
88
|
|
|
|
110
|
|
|
|
137
|
|
Europe
|
|
|
259
|
|
|
|
283
|
|
|
|
274
|
|
Asia and other
|
|
|
266
|
|
|
|
219
|
|
|
|
133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
613
|
|
|
|
612
|
|
|
|
544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels of oil equivalent* (thousands of barrels per day)
|
|
|
377
|
|
|
|
359
|
|
|
|
335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Reflects natural gas production
converted on the basis of relative energy content (six mcf
equals one barrel). |
United States: Crude oil and natural
gas production was lower in 2007 compared with 2006 and 2005,
principally due to natural decline and asset sales.
Europe: Crude oil production in 2007
was lower than in 2006, reflecting natural decline, facilities
work on three North Sea fields, and the sale of the
Corporations interests in the Scott and Telford fields in
the United Kingdom. These decreases were partially offset by
increased production in Russia. Decreased natural gas production
in 2007 compared with 2006 was principally due to lower
nominations related to the shut-down of a non-operated pipeline
in the North Sea and natural decline, partially offset by higher
production from the Atlantic and Cromarty natural gas fields in
the United Kingdom which commenced in June 2006. Production in
Europe was comparable in 2006 and 2005, reflecting increased
production from Russia and new production from the Atlantic and
Cromarty fields, which offset lower production due to
maintenance and natural decline.
Africa: Crude oil production increased
in 2007 compared with 2006 primarily due to the
start-up of
the Okume Complex in Equatorial Guinea in December 2006.
Production in 2006 was higher than 2005 levels, principally due
to production from Libya, which the Corporation re-entered in
January 2006.
Asia and other: Crude oil production
increased in 2007 versus 2006, reflecting a combination of an
increased entitlement and higher production in Azerbaijan.
Higher natural gas production in 2007 compared with 2006 was
principally due to new production from the Sinphuhorm onshore
gas project in Thailand which commenced in November 2006 and new
production from the Ujung Pangkah Field in Indonesia which
commenced in April 2007. These increases were partially offset
by the planned shut-down of the JDA to install facilities
required for Phase 2 gas sales. Natural gas production was
higher in 2006 compared with 2005 due to increased production
from the JDA.
Sales volumes: Higher sales volumes
increased revenue by approximately $240 million in 2007
compared with 2006 and $400 million in 2006 compared with
2005.
Operating costs and depreciation, depletion and
amortization: Cash operating costs,
consisting of production expenses and general and administrative
expenses, increased by $409 million in 2007 and
$322 million in 2006 compared with the corresponding
amounts in prior years (excluding the charges for
23
vacated leased office space and hurricane related costs in
2006). The increases in 2007 and 2006 were primarily due to
higher production volumes, increased costs of services and
materials, higher employee costs and increased production taxes.
Cash operating costs per barrel of oil equivalent were $13.36 in
2007, $10.92 in 2006 and $9.07 in 2005. Cash operating costs in
2008 are estimated to be in the range of $14.00 to $15.00 per
barrel of oil equivalent.
Excluding the pre-tax amount of the 2007 asset impairments,
depreciation, depletion and amortization charges increased by
$232 million and $194 million in 2007 and 2006,
respectively. The increases were primarily due to higher
production volumes and per barrel costs. Depreciation, depletion
and amortization costs per barrel of oil equivalent were $10.11
in 2007, $8.85 in 2006 and $7.88 in 2005. Depreciation,
depletion and amortization costs for 2008 are expected to be in
the range of $12.50 to $13.50 per barrel.
Exploration expenses: Exploration
expenses were lower in 2007 compared with 2006, primarily
reflecting lower dry hole costs, partially offset by increased
costs related to seismic studies. Exploration expenses were
higher in 2006 compared with 2005, principally reflecting higher
dry hole costs.
Income taxes: The effective income tax
rate for Exploration and Production operations was 50% in 2007,
53% in 2006 and 41% in 2005. After considering the items in the
table below, the effective income tax rates were 50% in 2007,
54% in 2006 and 42% in 2005. The effective income tax rate
increased beginning in 2006 due to the Corporations
re-entry into Libya and the increase in the supplementary tax on
petroleum operations in the United Kingdom from 10% to 20%. The
effective income tax rate for E&P operations in 2008 is
expected to be in the range of 47% to 51%.
Other: The after-tax foreign currency
loss was $7 million in 2007, compared with a gain of
$10 million in 2006 and $20 million in 2005.
Reported Exploration and Production earnings include the
following items of income (expense) before and after income
taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Income Taxes
|
|
|
After Income Taxes
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Gains from asset sales
|
|
$
|
21
|
|
|
$
|
369
|
|
|
$
|
48
|
|
|
$
|
15
|
|
|
$
|
236
|
|
|
$
|
41
|
|
Asset impairments
|
|
|
(112
|
)
|
|
|
|
|
|
|
|
|
|
|
(56
|
)
|
|
|
|
|
|
|
|
|
Estimated production imbalance settlements
|
|
|
(64
|
)
|
|
|
|
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
Income tax adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
11
|
|
Accrued office closing costs
|
|
|
|
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
(18
|
)
|
|
|
|
|
Hurricane related costs
|
|
|
|
|
|
|
|
|
|
|
(40
|
)
|
|
|
|
|
|
|
|
|
|
|
(26
|
)
|
Legal settlement
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(155
|
)
|
|
$
|
339
|
|
|
$
|
27
|
|
|
$
|
(74
|
)
|
|
$
|
173
|
|
|
$
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007: The gain from asset sales relates to the
sale of the Corporations interests in the Scott and
Telford fields located in the United Kingdom North Sea. The
charge for asset impairments relates to two mature fields in the
United Kingdom North Sea. The pre-tax amount of this charge is
reflected in depreciation, depletion and amortization. The
estimated production imbalance settlements represent a charge
for adjustments to prior meter readings at two offshore fields,
which are recorded as a reduction of sales and other operating
revenues.
2006: The gains from asset sales relate to the
sale of certain United States oil and gas producing properties
located in the Permian Basin in Texas and New Mexico and onshore
Gulf Coast. The accrued office closing cost relates to vacated
leased office space in the United Kingdom. The related expenses
are reflected principally in general and administrative
expenses. The income tax adjustment represents a one-time
adjustment to the Corporations deferred tax liability
resulting from an increase in the supplementary tax on petroleum
operations in the United Kingdom from 10% to 20%.
2005: The gains from asset sales represent the
disposal of non-producing properties in the United Kingdom and
the exchange of a mature North Sea asset for an increased
interest in the Ujung Pangkah Field in Indonesia. The
Corporation recorded incremental production expenses in 2005,
principally repair costs and higher insurance
24
premiums, as a result of hurricane damage in the Gulf of Mexico.
The income tax adjustment reflects the effect on deferred income
taxes of a reduction in the income tax rate in Denmark and a tax
settlement in the United Kingdom. The legal settlement reflects
the favorable resolution of contingencies on a prior year asset
sale, which is recorded in other income in the income statement.
The Corporations future Exploration and Production
earnings may be impacted by external factors, such as political
risk, volatility in the selling prices of crude oil and natural
gas, reserve and production changes, industry cost inflation,
exploration expenses, the effects of weather and changes in
foreign exchange and income tax rates.
Marketing
and Refining
Earnings from Marketing and Refining activities amounted to
$300 million in 2007, $394 million in 2006 and
$499 million in 2005. After considering the Marketing and
Refining items in the table on page 21, the earnings
amounted to $276 million in 2007, $394 million in 2006
and $475 million in 2005 and are discussed in the
paragraphs below. The Corporations downstream operations
include its 50% interest in HOVENSA, which is accounted for
using the equity method. Additional Marketing and Refining
activities include a fluid catalytic cracking facility in Port
Reading, New Jersey, as well as retail gasoline stations, energy
marketing and trading operations.
Refining: Refining earnings, which
consist of the Corporations share of HOVENSAs
results, Port Reading earnings, interest income on a note
receivable from PDVSA and results of other miscellaneous
operating activities were $193 million in 2007,
$240 million in 2006 and $330 million in 2005.
The Corporations share of HOVENSAs net income was
$108 million ($176 million before income taxes) in
2007, $124 million ($201 million before income taxes)
in 2006 and $227 million ($370 million before income
taxes) in 2005. The lower earnings in 2007 and 2006 compared to
the respective prior years were principally due to lower
refining margins. During 2007, the coker unit at HOVENSA was
shutdown for approximately 30 days for a scheduled
turnaround. Certain related processing units were also included
in this turnaround. In 2006, the fluid catalytic cracking unit
at HOVENSA was shutdown for approximately 22 days of
unscheduled maintenance. During 2005, a crude unit and the fluid
catalytic cracking unit at HOVENSA were each shutdown for
approximately 30 days of scheduled maintenance. Cash
distributions from HOVENSA were $300 million in 2007,
$400 million in 2006 and $275 million in 2005.
Pre-tax interest income on the PDVSA note was $9 million,
$15 million and $20 million in 2007, 2006 and 2005,
respectively. Interest income is reflected in other income in
the income statement. At December 31, 2007, the remaining
balance of the PDVSA note was $76 million, which is
scheduled to be fully repaid by February 2009.
Port Readings after-tax earnings were $75 million in
2007, $104 million in 2006 and $88 million in 2005.
Refined product margins were lower in 2007 compared with 2006.
Higher refined product sales volumes were offset by lower
margins in 2006 compared with 2005. In 2005, the Port Reading
facility was shutdown for 36 days of planned maintenance.
The following table summarizes refinery utilization rates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
|
|
|
Refinery Utilization
|
|
|
|
Capacity
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands of
|
|
|
|
|
|
|
|
|
|
|
|
|
barrels per day)
|
|
|
|
|
|
|
|
|
|
|
|
HOVENSA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
|
|
|
500
|
|
|
|
90.8%
|
|
|
|
89.7%
|
|
|
|
92.2%
|
|
Fluid catalytic cracker
|
|
|
150
|
|
|
|
87.1%
|
|
|
|
84.3%
|
|
|
|
81.9%
|
|
Coker
|
|
|
58
|
|
|
|
83.4%
|
|
|
|
84.3%
|
|
|
|
92.8%
|
|
Port Reading
|
|
|
65
|
|
|
|
93.2%
|
|
|
|
97.4%
|
|
|
|
85.3%
|
|
Marketing: Marketing operations, which
consist principally of retail gasoline and energy marketing
activities, generated income of $59 million in 2007,
$108 million in 2006 and $112 million in 2005,
excluding income from liquidations of LIFO inventories and the
charge related to a customer bankruptcy described on
page 26.
25
The decreases in 2007 and 2006 primarily reflect lower margins
on refined product sales. Total refined product sales volumes
were 451,000 barrels per day in 2007, 459,000 barrels
per day in 2006 and 456,000 barrels per day in 2005. Total
energy marketing natural gas sales volumes, including utility
and spot sales, were approximately 1.9 million mcf per day
in 2007, 1.8 million mcf per day in 2006 and
1.7 million mcf per day in 2005. In addition, energy
marketing sold electricity volumes at the rate of 2,800, 1,400
and 500 megawatts (round the clock) in 2007, 2006 and 2005,
respectively.
The Corporation has a 50% voting interest in a consolidated
partnership that trades energy commodities and energy
derivatives. The Corporation also takes trading positions for
its own account. The Corporations after-tax results from
trading activities, including its share of the earnings of the
trading partnership, amounted to income of $24 million in
2007, $46 million in 2006 and $33 million in 2005.
Marketing expenses were comparable in 2007 and 2006, but
increased in 2006 compared with 2005, due to higher expenses
from an increased number of retail convenience stores, growth in
energy marketing operations and increased utility and
compensation related costs.
Reported Marketing and Refining earnings include the following
items of income (expense) before and after income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Income Taxes
|
|
|
After Income Taxes
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
LIFO inventory liquidations
|
|
$
|
38
|
|
|
$
|
|
|
|
$
|
51
|
|
|
$
|
24
|
|
|
$
|
|
|
|
$
|
32
|
|
Charge related to customer bankruptcy
|
|
|
|
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
38
|
|
|
$
|
|
|
|
$
|
38
|
|
|
$
|
24
|
|
|
$
|
|
|
|
$
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2007 and 2005, Marketing and Refining earnings include income
from the liquidation of prior year LIFO inventories. In 2005,
Marketing and Refining earnings also include a charge resulting
from the bankruptcy of a customer in the utility industry, which
is included in marketing expenses.
The Corporations future Marketing and Refining earnings
may be impacted by volatility in margins, competitive industry
conditions, government regulatory changes, credit risk and
supply and demand factors, including the effects of weather.
Corporate
The following table summarizes corporate expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Corporate expenses (excluding the items listed below)
|
|
$
|
187
|
|
|
$
|
156
|
|
|
$
|
119
|
|
Income taxes (benefits) on the above
|
|
|
(62
|
)
|
|
|
(46
|
)
|
|
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125
|
|
|
|
110
|
|
|
|
93
|
|
Items affecting comparability between periods, after tax
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated MTBE litigation
|
|
|
25
|
|
|
|
|
|
|
|
|
|
Tax on repatriated earnings
|
|
|
|
|
|
|
|
|
|
|
72
|
|
Premiums on bond repurchases
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net corporate expenses
|
|
$
|
150
|
|
|
$
|
110
|
|
|
$
|
191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding the items affecting comparability between periods, the
increase in corporate expenses in 2007 compared with 2006
primarily reflects higher employee related costs, including
stock-based compensation. The increase in corporate expenses in
2006 compared with 2005 principally reflects the expensing of
stock options
26
commencing January 1, 2006 and increases in insurance
costs. Recurring after-tax corporate expenses in 2008 are
estimated to be in the range of $130 to $140 million.
In 2007, Corporate expenses include a charge of $25 million
($40 million before income taxes) related to MTBE
litigation. The pre-tax amount of this charge is recorded in
general and administrative expenses. In 2005, the American Jobs
Creation Act provided for a one-time reduction in the income tax
rate to 5.25% on the remittance of eligible dividends from
foreign subsidiaries to a United States parent. The Corporation
repatriated $1.9 billion of previously unremitted foreign
earnings resulting in the recognition of an income tax provision
of $72 million. The pre-tax amount of bond repurchase
premiums in 2005 was $39 million, which was recorded in
other income in the income statement.
Interest
After-tax interest expense was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Total interest incurred
|
|
$
|
306
|
|
|
$
|
301
|
|
|
$
|
304
|
|
Less capitalized interest
|
|
|
50
|
|
|
|
100
|
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense before income taxes
|
|
|
256
|
|
|
|
201
|
|
|
|
224
|
|
Less income taxes
|
|
|
96
|
|
|
|
74
|
|
|
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After-tax interest expense
|
|
$
|
160
|
|
|
$
|
127
|
|
|
$
|
140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in capitalized interest in 2007 reflects the
completion of several development projects in 2007 and the
latter portion of 2006. After-tax interest expense in 2008 is
expected to be in the range of $165 to $175 million,
principally reflecting lower capitalized interest.
Sales
and Other Operating Revenues
Sales and other operating revenues totaled $31,647 million
in 2007, an increase of 13% compared with 2006. The increase
reflects higher selling prices and sales volumes of crude oil,
higher refined product selling prices and increased sales
volumes in electricity. In 2006, sales and other operating
revenues totaled $28,067 million, an increase of 23%
compared with 2005. The increase reflects higher selling prices
of crude oil, higher sales volumes and reduced crude oil hedge
positions in Exploration and Production activities and higher
selling prices and sales volumes in marketing activities.
The change in cost of goods sold in each year principally
reflects the change in sales volumes and prices of refined
products and purchased natural gas and electricity.
Liquidity
and Capital Resources
The following table sets forth certain relevant measures of the
Corporations liquidity and capital resources as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Cash and cash equivalents
|
|
$
|
607
|
|
|
$
|
383
|
|
Current portion of long-term debt
|
|
$
|
62
|
|
|
$
|
27
|
|
Total debt
|
|
$
|
3,980
|
|
|
$
|
3,772
|
|
Stockholders equity
|
|
$
|
9,774
|
|
|
$
|
8,147
|
|
Debt to capitalization ratio*
|
|
|
28.9
|
%
|
|
|
31.6
|
%
|
|
|
|
* |
|
Total debt as a percentage of
the sum of total debt plus stockholders equity. |
27
Cash
Flows
The following table sets forth a summary of the
Corporations cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
3,507
|
|
|
$
|
3,491
|
|
|
$
|
1,840
|
|
Investing activities
|
|
|
(3,474
|
)
|
|
|
(3,289
|
)
|
|
|
(2,255
|
)
|
Financing activities
|
|
|
191
|
|
|
|
(134
|
)
|
|
|
(147
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
224
|
|
|
$
|
68
|
|
|
$
|
(562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities: Net cash provided
by operating activities, including changes in operating assets
and liabilities, was comparable in 2007 and 2006. Net cash
provided by operating activities increased to
$3,491 million in 2006 from $1,840 million in 2005,
principally reflecting higher earnings, changes in working
capital accounts and increased distributions from HOVENSA. The
Corporation received cash distributions from HOVENSA of
$300 million in 2007, $400 million in 2006 and
$275 million in 2005.
Investing Activities: The following
table summarizes the Corporations capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
|
|
$
|
371
|
|
|
$
|
590
|
|
|
$
|
229
|
|
Production and development
|
|
|
2,605
|
|
|
|
2,164
|
|
|
|
1,598
|
|
Acquisitions (including leaseholds)
|
|
|
462
|
|
|
|
921
|
|
|
|
408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,438
|
|
|
|
3,675
|
|
|
|
2,235
|
|
Marketing, Refining and Corporate
|
|
|
140
|
|
|
|
169
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,578
|
|
|
$
|
3,844
|
|
|
$
|
2,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures in 2007 include the acquisition of a 28%
interest in the Genghis Khan Field in the deepwater Gulf of
Mexico for $371 million. In 2006, capital expenditures
included payments of $359 million to
re-enter the
Corporations former oil and gas production operations in
the Waha concessions in Libya and $413 million to acquire a
55% working interest in the West Med Block in Egypt.
In 2007 the Corporation received proceeds of $93 million
for the sale of its interests in the Scott and Telford fields
located in the United Kingdom. Proceeds from asset sales in 2006
totaled $444 million, including the sale of the
Corporations interests in certain producing properties in
the Permian Basin and onshore U.S. Gulf Coast. Proceeds
from asset sales were $74 million in 2005, principally from
the sale of non-producing properties.
Financing Activities: During 2007, net
borrowings were $208 million. The Corporation reduced debt
by $13 million in 2006 and $50 million in 2005. In
2005, bond repurchases of $600 million were funded by
borrowings on the revolving credit facility in connection with
the repatriation of foreign earnings to the United States.
Common stock dividends paid were $127 million in 2007.
Total common and preferred stock dividends paid were
$161 million in 2006 and $159 million in 2005. The
Corporation received net proceeds from the exercise of stock
options totaling $110 million, $40 million and
$62 million in 2007, 2006 and 2005, respectively.
Future
Capital Requirements and Resources
The Corporation anticipates $4.4 billion in capital and
exploratory expenditures in 2008, of which $4.3 billion
relates to Exploration and Production operations. The
Corporation has maturities of long-term debt of $62 million
in 2008 and $143 million in 2009. The Corporation
anticipates that it can fund its 2008 operations, including
capital
28
expenditures, dividends, pension contributions and required debt
repayments, with existing cash on-hand, projected cash flow from
operations and its available credit facilities.
The Corporation maintains a $3.0 billion syndicated,
revolving credit facility (the facility), substantially all of
which is committed through May 2012. The facility can be used
for borrowings and letters of credit. At December 31, 2007,
outstanding borrowings under the facility were $220 million
and additional available borrowing capacity under the facility
was $2,780 million.
The Corporation has a
364-day
asset-backed credit facility securitized by certain accounts
receivable from its Marketing and Refining operations, which are
sold to a wholly-owned subsidiary. Under the terms of this
financing arrangement, the Corporation has the ability to borrow
up to $800 million, subject to the availability of
sufficient levels of eligible receivables. At December 31,
2007, the Corporation had $250 million in outstanding
borrowings and outstanding letters of credit of
$534 million which were collateralized by
$1,336 million of Marketing and Refining accounts
receivable. These receivables are not available to pay the
general obligations of the Corporation before repayment of
outstanding borrowings under the asset-backed facility.
At December 31, 2007, $600 million of outstanding
borrowings under short-term credit facilities are classified as
long term based on the Corporations available capacity
under the committed revolving credit facility. These borrowings
consist of the $250 million under the asset-backed credit
facility described above, $300 million under a short-term
committed facility and $50 million under uncommitted lines
at December 31, 2007. The Corporation also has a shelf
registration under which it may issue additional debt
securities, warrants, common stock or preferred stock.
Outstanding letters of credit at December 31, were as
follows:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Revolving credit facility
|
|
$
|
|
|
|
$
|
1
|
|
Asset-backed credit facility
|
|
|
534
|
|
|
|
|
|
Committed short-term letter of credit facilities
|
|
|
995
|
|
|
|
1,875
|
|
Uncommitted lines
|
|
|
1,510
|
|
|
|
1,603
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,039
|
|
|
$
|
3,479
|
|
|
|
|
|
|
|
|
|
|
A loan agreement covenant based on the Corporations debt
to equity ratio allows the Corporation to borrow up to an
additional $12.3 billion for the construction or
acquisition of assets at December 31, 2007. The Corporation
has the ability to borrow up to an additional $2.6 billion
of secured debt at December 31, 2007 under the loan
agreement covenants.
Credit
Ratings
There are three major credit rating agencies that rate the
Corporations debt. All three agencies have currently
assigned an investment grade rating to the Corporations
debt. The interest rates and facility fees charged on the
Corporations borrowing arrangements and margin
requirements from non-trading and trading counterparties are
subject to adjustment if the Corporations credit rating
changes.
29
Contractual
Obligations and Contingencies
Following is a table showing aggregated information about
certain contractual obligations at December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
2009 and
|
|
|
2011 and
|
|
|
|
|
|
|
Total
|
|
|
2008
|
|
|
2010
|
|
|
2012
|
|
|
Thereafter
|
|
|
|
(Millions of dollars)
|
|
|
Long-term debt(a)
|
|
$
|
3,980
|
|
|
$
|
62
|
|
|
$
|
172
|
|
|
$
|
1,543
|
|
|
$
|
2,203
|
|
Operating leases
|
|
|
3,233
|
|
|
|
382
|
|
|
|
849
|
|
|
|
588
|
|
|
|
1,414
|
|
Purchase obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply commitments
|
|
|
38,548
|
|
|
|
9,805
|
|
|
|
14,560
|
|
|
|
14,058
|
|
|
|
125
|
(b)
|
Capital expenditures
|
|
|
1,951
|
|
|
|
1,118
|
|
|
|
833
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
977
|
|
|
|
537
|
|
|
|
230
|
|
|
|
105
|
|
|
|
105
|
|
Other long-term liabilities
|
|
|
1,579
|
|
|
|
98
|
|
|
|
481
|
|
|
|
222
|
|
|
|
778
|
|
|
|
|
(a) |
|
At December 31, 2007, the
Corporations debt bears interest at a weighted average
rate of 7.0%. |
|
(b) |
|
The Corporation intends to
continue purchasing refined product supply from HOVENSA.
Estimated future purchases amount to approximately
$7.0 billion annually using year-end 2007 prices. |
In the preceding table, the Corporations supply
commitments include its estimated purchases of 50% of
HOVENSAs production of refined products, after anticipated
sales by HOVENSA to unaffiliated parties. The value of future
supply commitments will fluctuate based on prevailing market
prices at the time of purchase, the actual output from HOVENSA,
and the level of sales to unaffiliated parties. Also included
are term purchase agreements at market prices for additional
gasoline necessary to supply the Corporations retail
marketing system and feedstocks for the Port Reading refining
facility. In addition, the Corporation has commitments to
purchase refined products, natural gas and electricity for use
in supplying contracted customers in its energy marketing
business. These commitments were computed based on year-end
market prices.
The table also reflects future capital expenditures, including a
portion of the Corporations planned $4.4 billion
capital investment program for 2008, that is contractually
committed at December 31, 2007. Obligations for operating
expenses include commitments for transportation, seismic
purchases, oil and gas production expenses and other normal
business expenses. Other long-term liabilities reflect
contractually committed obligations on the balance sheet at
December 31, 2007, including asset retirement obligations,
pension plan funding requirements and anticipated obligations
for uncertain income tax positions.
The Corporation and certain of its subsidiaries lease gasoline
stations, drilling rigs, tankers, office space and other assets
for varying periods under leases accounted for as operating
leases. During 2007, the Corporation entered into a lease
agreement for a new drillship and related support services for
use in its global deepwater exploration and development
activities beginning in the middle of 2009. The total payments
under this five year contract will approximate $950 million.
The Corporation has a contingent purchase obligation, expiring
in April 2010, to acquire the remaining interest in WilcoHess, a
retail gasoline station joint venture, for approximately
$150 million as of December 31, 2007.
The Corporation guarantees the payment of up to 50% of
HOVENSAs crude oil purchases from suppliers other than
PDVSA. The amount of the Corporations guarantee fluctuates
based on the volume of crude oil purchased and related prices
and at December 31, 2007 amounted to $277 million. In
addition, the Corporation has agreed to provide funding up to a
maximum of $15 million to the extent HOVENSA does not have
funds to meet its senior debt obligations.
At December 31, 2007, the Corporation has issued
$2,978 million of letters of credit principally relating to
accrued liabilities with hedging and trading counterparties
recorded on its balance sheet. In addition, the
30
Corporation is contingently liable under letters of credit and
under guarantees of the debt of other entities directly related
to its business, as follows:
|
|
|
|
|
|
|
Total
|
|
|
|
(Millions of
|
|
|
|
dollars)
|
|
|
Letters of credit
|
|
$
|
61
|
|
Guarantees
|
|
|
292
|
*
|
|
|
|
|
|
|
|
$
|
353
|
|
|
|
|
|
|
|
|
|
* |
|
Includes $277 million for
the HOVENSA crude oil purchases guarantee and the
$15 million guarantee on HOVENSAs debt which are
discussed on page 30. |
Off-Balance
Sheet Arrangements
The Corporation has leveraged leases not included in its balance
sheet, primarily related to retail gasoline stations that the
Corporation operates. The net present value of these leases is
$493 million at December 31, 2007 compared with
$490 million at December 31, 2006. The
Corporations December 31, 2007 debt to capitalization
ratio would increase from 28.9% to 31.4% if these leases were
included as debt.
See also Contractual Obligations and
Contingencies on page 30, Note 4,
Refining Joint Venture, and Note 15,
Guarantees and Contingencies, in the notes to the
financial statements.
Stock
Split
On May 3, 2006, the Corporations shareholders voted
to increase the number of authorized common shares from
200 million to 600 million and the board of directors
declared a three-for-one stock split. The stock split was
completed in the form of a stock dividend that was issued on
May 31, 2006. The common share par value remained at $1.00
per share. All common share and per share amounts in the
financial statements and notes and managements discussion
and analysis are on an after-split basis for all periods
presented.
Foreign
Operations
The Corporation conducts exploration and production activities
principally in Algeria, Australia, Azerbaijan, Brazil, Denmark,
Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya,
Malaysia, Norway, Russia, Thailand, the United Kingdom and the
United States. Therefore, the Corporation is subject to the
risks associated with foreign operations. These exposures
include political risk (including tax law changes) and currency
risk.
HOVENSA owns and operates a refinery in the United States Virgin
Islands. In 2002, there was a political disruption in Venezuela
that reduced the availability of Venezuelan crude oil used in
refining operations; however, this disruption did not have a
material adverse effect on the Corporations financial
position. The Corporation has a note receivable of
$76 million at December 31, 2007 from a subsidiary of
PDVSA. All payments are current and the Corporation anticipates
collection of the remaining balance.
See also Item 1A. Risk Factors Related to Our Business
and Operations.
Accounting
Policies
Critical
Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of
assets and liabilities on the Corporations balance sheet
and revenues and expenses on the income statement. The
accounting methods used can affect net income,
stockholders equity and various financial statement
ratios. However, the Corporations accounting policies
generally do not change cash flows or liquidity.
Accounting for Exploration and Development
Costs: Exploration and production activities
are accounted for using the successful efforts method. Costs of
acquiring unproved and proved oil and gas leasehold acreage,
including lease bonuses, brokers fees and other related
costs, are capitalized. Annual lease rentals, exploration
31
expenses and exploratory dry hole costs are expensed as
incurred. Costs of drilling and equipping productive wells,
including development dry holes, and related production
facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves
are capitalized pending determination of whether proved reserves
have been found. Exploratory drilling costs remain capitalized
after drilling is completed if (1) the well has found a
sufficient quantity of reserves to justify completion as a
producing well and (2) sufficient progress is being made in
assessing the reserves and the economic and operating viability
of the project. If either of those criteria is not met, or if
there is substantial doubt about the economic or operational
viability of the project, the capitalized well costs are charged
to expense. Indicators of sufficient progress in assessing
reserves and the economic and operating viability of a project
include: commitment of project personnel, active negotiations
for sales contracts with customers, negotiations with
governments, operators and contractors and firm plans for
additional drilling and other factors.
Crude Oil and Natural Gas Reserves: The
determination of estimated proved reserves is a significant
element in arriving at the results of operations of exploration
and production activities. The estimates of proved reserves
affect well capitalizations, the unit of production depreciation
rates of proved properties and wells and equipment, as well as
impairment testing of oil and gas assets and goodwill.
The Corporations oil and gas reserves are calculated in
accordance with SEC regulations and interpretations and the
requirements of the Financial Accounting Standards Board. For
reserves to be booked as proved they must be commercially
producible, government and project operator approvals must be
obtained and, depending on the amount of the project cost,
senior management or the board of directors must commit to fund
the project. The Corporations oil and gas reserve
estimation and reporting process involves an annual independent
third party reserve determination as well as internal technical
appraisals of reserves. The Corporation maintains its own
internal reserve estimates that are calculated by technical
staff that work directly with the oil and gas properties. The
Corporations technical staff updates reserve estimates
throughout the year based on evaluations of new wells,
performance reviews, new technical data and other studies. To
provide consistency throughout the Corporation, standard reserve
estimation guidelines, definitions, reporting reviews and
approval practices are used. The internal reserve estimates are
subject to internal technical audits and senior management
reviews the estimates.
The oil and gas reserve estimates reported in the Supplementary
Oil and Gas Data in accordance with Statement of Financial
Accounting Standards (FAS) No. 69 Disclosures about Oil
and Gas Producing Activities (FAS No. 69) are
determined independently by the consulting firm of DeGolyer and
MacNaughton (D&M) and are consistent with internal
estimates. Annually, the Corporation provides D&M with
engineering, geological and geophysical data, actual production
histories and other information necessary for the reserve
determination. The Corporations and D&Ms
technical staffs meet to review and discuss the information
provided. Senior management and the Board of Directors review
the final reserve estimates issued by D&M.
Impairment of Long-Lived Assets and
Goodwill: As explained below there are
significant differences in the way long-lived assets and
goodwill are evaluated and measured for impairment testing. The
Corporation reviews long-lived assets, including oil and gas
fields, for impairment whenever events or changes in
circumstances indicate that the carrying amounts may not be
recovered. Long-lived assets are tested based on identifiable
cash flows (the field level for oil and gas assets) and are
largely independent of the cash flows of other assets and
liabilities. If the carrying amounts of the long-lived assets
are not expected to be recovered by undiscounted future net cash
flow estimates, the assets are impaired and an impairment loss
is recorded. The amount of impairment is based on the estimated
fair value of the assets generally determined by discounting
anticipated future net cash flows.
In the case of oil and gas fields, the present value of future
net cash flows is based on managements best estimate of
future prices, which is determined with reference to recent
historical prices and published forward prices, applied to
projected production volumes of individual fields and discounted
at a rate commensurate with the risks involved. The projected
production volumes represent reserves, including probable
reserves, expected to be produced based on a stipulated amount
of capital expenditures. The production volumes, prices and
timing of production are consistent with internal projections
and other externally reported information. Oil and gas prices
used for determining asset impairments will generally differ
from those used in the standardized measure of discounted future
net cash flows, since the standardized measure requires the use
of actual prices on the last day of the year.
32
The Corporations impairment tests of long-lived
Exploration and Production producing assets are based on its
best estimates of future production volumes (including recovery
factors), selling prices, operating and capital costs, the
timing of future production and other factors, which are updated
each time an impairment test is performed. The Corporation could
have impairments if the projected production volumes from oil
and gas fields decrease, crude oil and natural gas selling
prices decline significantly for an extended period or future
estimated capital and operating costs increase significantly.
In accordance with FAS No. 142 Goodwill and Other
Intangible Assets (FAS No. 142), the
Corporations goodwill is not amortized, but is tested for
impairment annually in the fourth quarter at a reporting unit
level, which is an operating segment or one level below an
operating segment. The reporting unit or units used to evaluate
and measure goodwill for impairment are determined primarily
from the manner in which the business is managed. The
Corporations goodwill is assigned to the Exploration and
Production operating segment and it expects that the benefits of
goodwill will be recovered through the operation of that segment.
The Corporations fair value estimate of the Exploration
and Production segment is the sum of: (1) the discounted
anticipated cash flows of producing assets and known
developments, (2) the estimated risk adjusted present value
of exploration assets, and (3) an estimated market premium
to reflect the market price an acquirer would pay for potential
synergies including cost savings, access to new business
opportunities, enterprise control, improved processes and
increased market share. The Corporation also considers the
relative market valuation of similar Exploration and Production
companies.
The determination of the fair value of the Exploration and
Production operating segment depends on estimates about oil and
gas reserves, future prices, timing of future net cash flows and
market premiums. Significant extended declines in crude oil and
natural gas prices or reduced reserve estimates could lead to a
decrease in the fair value of the Exploration and Production
operating segment that could result in an impairment of goodwill.
Because there are significant differences in the way long-lived
assets and goodwill are evaluated and measured for impairment
testing, there may be impairments of individual assets that
would not cause an impairment of the goodwill assigned to the
Exploration and Production segment.
Asset Retirement Obligations: The
Corporation has material legal obligations to remove and
dismantle long lived assets and to restore land or seabed at
certain exploration and production locations. In accordance with
generally accepted accounting principles, the Corporation
recognizes a liability for the fair value of required asset
retirement obligations. In addition, the fair value of any
legally required conditional asset retirement obligations is
recorded if the liability can be reasonably estimated. The
Corporation capitalizes such costs as a component of the
carrying amount of the underlying assets in the period in which
the liability is incurred. In order to measure these
obligations, the Corporation estimates the fair value of the
obligations by discounting the future payments that will be
required to satisfy the obligations. In determining these
estimates, the Corporation is required to make several
assumptions and judgments related to the scope of dismantlement,
timing of settlement, interpretation of legal requirements,
inflationary factors and discount rate. In addition, there are
other external factors which could significantly affect the
ultimate settlement costs for these obligations including:
changes in environmental regulations and other statutory
requirements, fluctuations in industry costs and foreign
currency exchange rates and advances in technology. As a result,
the Corporations estimates of asset retirement obligations
are subject to revision due to the factors described above.
Changes in estimates prior to settlement result in adjustments
to both the liability and related asset values.
Derivatives: The Corporation utilizes
derivative instruments for both non-trading and trading
activities. In non-trading activities, the Corporation uses
futures, forwards, options and swaps, individually or in
combination to mitigate its exposure to fluctuations in the
prices of crude oil, natural gas, refined products and
electricity, and changes in foreign currency exchange rates. In
trading activities, the Corporation, principally through a
consolidated partnership, trades energy commodities and
derivatives, including futures, forwards, options and swaps,
based on expectations of future market conditions.
All derivative instruments are recorded at fair value in the
Corporations balance sheet. The Corporations policy
for recognizing the changes in fair value of derivatives varies
based on the designation of the derivative. The changes in fair
value of derivatives that are not designated as hedges under
FAS No. 133 are recognized currently in
33
earnings. Derivatives may be designated as hedges of expected
future cash flows or forecasted transactions (cash flow hedges)
or hedges of firm commitments (fair value hedges). The effective
portion of changes in fair value of derivatives that are
designated as cash flow hedges is recorded as a component of
other comprehensive income (loss). Amounts included in
accumulated other comprehensive income (loss) for cash flow
hedges are reclassified into earnings in the same period that
the hedged item is recognized in earnings. The ineffective
portion of changes in fair value of derivatives designated as
cash flow hedges is recorded currently in earnings. Changes in
fair value of derivatives designated as fair value hedges are
recognized currently in earnings. The change in fair value of
the related hedged commitment is recorded as an adjustment to
its carrying amount and recognized currently in earnings.
Derivatives that are designated as either cash flow or fair
value hedges are tested for effectiveness prospectively before
they are executed and both prospectively and retrospectively on
an on-going basis to determine whether they continue to qualify
for hedge accounting. The prospective and retrospective
effectiveness calculations are performed using either historical
simulation or other statistical models, which utilize historical
observable market data consisting of futures curves and spot
prices.
Income Taxes: Judgments are required in
the determination and recognition of income tax assets and
liabilities in the financial statements. These judgements
include the requirement to only recognize the financial
statement effect of a tax position when management believes that
it is more likely than not, that based on the technical merits,
the position will be sustained upon examination.
The Corporation has net operating loss carryforwards in several
jurisdictions, including the United States, and has recorded
deferred tax assets for those losses. Additionally, the
Corporation has deferred tax assets due to temporary differences
between the book basis and tax basis of certain assets and
liabilities. Regular assessments are made as to the likelihood
of those deferred tax assets being realized. If it is more
likely than not that some or all of the deferred tax assets will
not be realized, a valuation allowance is recorded to reduce the
deferred tax assets to the amount that is expected to be
realized. In evaluating realizability of deferred tax assets,
the Corporation refers to the reversal periods for temporary
differences, available carryforward periods for net operating
losses, estimates of future taxable income, the availability of
tax planning strategies, the existence of appreciated assets and
other factors. Estimates of future taxable income are based on
assumptions of oil and gas reserves and selling prices that are
consistent with the Corporations internal business
forecasts. The Corporation does not provide for deferred
U.S. income taxes applicable to undistributed earnings of
foreign subsidiaries that are indefinitely reinvested in foreign
operations.
Changes
in Accounting Policies
Effective January 1, 2007, the Corporation adopted
Financial Accounting Standards Board (FASB) Staff Position (FSP)
AUG AIR-1, Accounting for Planned Major Maintenance
Activities. This FSP eliminated the previously acceptable
accrue-in-advance
method of accounting for planned major maintenance. As a result,
the Corporation retrospectively changed its method of accounting
to recognize expenses associated with refinery turnarounds when
such costs are incurred. The impact of adopting this FSP
increased previously reported 2006 earnings by $4 million
($.01 per diluted share). In addition, previously reported
2005 net income decreased by $16 million ($.05 per
diluted share) and retained earnings as of January 1, 2005
increased by approximately $48 million. All 2007, 2006 and
2005 financial information reflects this retrospective
accounting change.
Effective January 1, 2007, the Corporation adopted the
provisions of FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes (FIN 48). FIN 48
prescribes the financial statement recognition and measurement
criteria for a tax position taken or expected to be taken in a
tax return. FIN 48 also requires additional disclosures
related to uncertain income tax positions. See Note 11,
Income Taxes for further information.
Recently
Issued Accounting Standard
In September 2006, the FASB issued FAS No. 157,
Fair Value Measurements (FAS No. 157).
FAS No. 157 establishes a framework for measuring fair
value and requires disclosure of a fair value hierarchy, which
applies to financial assets and liabilities measured at fair
value under other authoritative accounting pronouncements. The
standard also requires additional disclosure about the methods
of determining fair value. The Corporation as
34
required, will prospectively adopt the provisions of
FAS No. 157 effective January 1, 2008. The
Corporation believes that the impact of adopting
FAS No. 157 on net income will not be material. In
addition, the Corporation expects to record a reduction in the
after-tax charge reflected in accumulated other comprehensive
income relating to the crude oil hedging program of
approximately $160 million, after income taxes.
Environment,
Health and Safety
The Corporation has implemented a values-based,
socially-responsible strategy focused on improving environment,
health and safety performance and making a positive impact on
communities. The strategy is supported by the Corporations
environment, health, safety and social responsibility
(EHS & SR) policies and by environment and safety
management systems that help protect the Corporations
workforce, customers and local communities. The
Corporations management systems are designed to uphold or
exceed international standards and are intended to promote
internal consistency, adherence to policy objectives and
continual improvement in EHS & SR performance.
Improved performance may, in the short-term, increase the
Corporations operating costs and could also require
increased capital expenditures to reduce potential risks to
assets, reputation and license to operate. In addition to
enhanced EHS & SR performance, improved productivity
and operational efficiencies may be realized as collateral
benefits from investments in EHS & SR. The Corporation
has programs in place to evaluate regulatory compliance, audit
facilities, train employees, prevent and manage risks and
emergencies and to generally meet corporate EHS & SR
goals.
The production of motor and other fuels in the United States and
elsewhere has faced increasing regulatory pressures in recent
years. In 2006, additional regulations to reduce the allowable
sulfur content in diesel fuel went into effect. Additional
reductions in gasoline and fuel oil sulfur content are under
consideration. Fuels production will likely continue to be
subject to more stringent regulation in future years and as such
may require additional capital expenditures. The Energy Policy
Act of 2005 imposes on refiners a requirement to use specific
quantities of renewable content in gasoline. The 2007 Energy
Policy Act expanded requirements on the use of renewable content
and included several technology forcing provisions. Many states
have also enacted or are considering biofuels mandates, which,
in combination with national legislation may affect the
Registrants markets for fuels.
As described in Item 3 Legal Proceedings, in
2003 the Corporation and HOVENSA began discussions with the
U.S. EPA regarding the EPAs Petroleum Refining
Initiative (PRI). The PRI is an ongoing program that is designed
to reduce certain air emissions at all U.S. refineries.
Since 2000, the EPA has entered into settlements addressing
these emissions with petroleum refining companies that control
over 80% of the domestic refining capacity. Negotiations with
the EPA are continuing and depending on the outcome of these
discussions, the Corporation and HOVENSA may experience
increased capital expenditures and operating expenses related to
air emissions controls. Settlements with other refiners allow
for controls to be phased in over several years.
The Corporation has undertaken a program to assess, monitor and
reduce the emission of greenhouse gases, including
carbon dioxide and methane. The challenges associated with this
program are significant, not only from the standpoint of
technical feasibility, but also from the perspective of
adequately measuring the Corporations greenhouse gas
inventory. The Corporation has completed a revised monitoring
protocol which will allow for better measurement of
greenhouse gases and has completed an independently
verified audit of its emissions. The monitoring protocol in
conjunction with the Corporations recently formulated
Climate Change Network will allow for better control of these
emissions and assist the Corporation in developing policies and
programs to reduce these emissions and comply with any future
regulatory restrictions.
The Corporation expects continuing expenditures for
environmental assessment and remediation related primarily to
existing conditions. Sites where corrective action may be
necessary include gasoline stations, terminals, onshore
exploration and production facilities, refineries (including
solid waste management units under permits issued pursuant to
the Resource Conservation and Recovery Act) and, although not
currently significant, Superfund sites where the
Corporation has been named a potentially responsible party.
The Corporation accrues for environmental assessment and
remediation expenses when the future costs are probable and
reasonably estimable. At year-end 2007, the Corporations
reserve for estimated environmental liabilities was
approximately $60 million. The Corporation expects that
existing reserves for environmental liabilities will adequately
cover costs to assess and remediate known sites. The
Corporations remediation spending
35
was $23 million in 2007 and $15 million in 2006 and
2005. Capital expenditures incurred over several years to comply
with low sulfur gasoline and diesel fuel requirements totaled
approximately $400 million at HOVENSA and approximately
$70 million at Port Reading. Capital expenditures for
facilities, primarily to comply with federal, state and local
environmental standards, other than for the low sulfur
requirements, were $22 million in 2007 and 2006 and
$3 million in 2005.
Forward-Looking
Information
Certain sections of Managements Discussion and Analysis of
Financial Condition and Results of Operations and Quantitative
and Qualitative Disclosures about Market Risk, including
references to the Corporations future results of
operations and financial position, liquidity and capital
resources, capital expenditures, oil and gas production, tax
rates, debt repayment, hedging, derivative, market risk and
environmental disclosures, off-balance sheet arrangements and
contractual obligations and contingencies include
forward-looking information. Forward-looking disclosures are
based on the Corporations current understanding and
assessment of these activities and reasonable assumptions about
the future. Actual results may differ from these disclosures
because of changes in market conditions, government actions and
other factors.
In the normal course of its business, the Corporation is exposed
to commodity risks related to changes in the price of crude oil,
natural gas, refined products and electricity, as well as to
changes in interest rates and foreign currency values. In the
disclosures that follow, these operations are referred to as
non-trading activities. The Corporation also has trading
operations, principally through a 50% voting interest in a
trading partnership. These activities are also exposed to
commodity risks primarily related to the prices of crude oil,
natural gas and refined products. The following describes how
these risks are controlled and managed.
Controls: The Corporation maintains a
control environment under the direction of its chief risk
officer and through its corporate risk policy, which the
Corporations senior management has approved. Controls
include volumetric, term and
value-at-risk
limits. In addition, the chief risk officer must approve the use
of new instruments or commodities. Risk limits are monitored
daily and exceptions are reported to business units and to
senior management. The Corporations risk management
department also performs independent verifications of sources of
fair values and validations of valuation models. These controls
apply to all of the Corporations non-trading and trading
activities, including the consolidated trading partnership. The
Corporations treasury department is responsible for
administering foreign exchange rate and interest rate hedging
programs.
Instruments: The Corporation primarily
uses forward commodity contracts, foreign exchange forward
contracts, futures, swaps, options and energy commodity based
securities in its non-trading and trading activities. These
contracts are generally widely traded instruments with
standardized terms. The following describes these instruments
and how the Corporation uses them:
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|
|
|
|
Forward Commodity Contracts: The Corporation
enters into contracts for the forward purchase and sale of
commodities. At settlement date, the notional value of the
contract is exchanged for physical delivery of the commodity.
Forward contracts that are designated as normal purchase and
sale contracts under FAS No. 133 are excluded from the
quantitative market risk disclosures.
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|
|
|
Forward Foreign Exchange Contracts: Forward
contracts include forward purchase contracts for both the
British pound sterling and the Danish kroner. These foreign
currency contracts commit the Corporation to purchase a fixed
amount of pound sterling and kroner at a predetermined exchange
rate on a certain date.
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|
|
|
Exchange Traded Contracts: The Corporation
uses exchange traded contracts, including futures, on a number
of different underlying energy commodities. These contracts are
settled daily with the relevant exchange and may be subject to
exchange position limits.
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|
|
|
Swaps: The Corporation uses financially
settled swap contracts with third parties as part of its hedging
and trading activities. Cash flows from swap contracts are
determined based on underlying commodity prices and are
typically settled over the life of the contract.
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36
|
|
|
|
|
Options: Options on various underlying energy
commodities include exchange traded and third party contracts
and have various exercise periods. As a seller of options, the
Corporation receives a premium at the outset and bears the risk
of unfavorable changes in the price of the commodity underlying
the option. As a purchaser of options, the Corporation pays a
premium at the outset and has the right to participate in the
favorable price movements in the underlying commodities. These
premiums are a component of the fair value of the options.
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|
|
Energy Securities: Energy securities include
energy related equity or debt securities issued by a company or
government or related derivatives on these securities.
|
Value-at-Risk: The
Corporation uses
value-at-risk
to monitor and control commodity risk within its trading and
non-trading activities. The
value-at-risk
model uses historical simulation and the results represent the
potential loss in fair value over one day at a 95% confidence
level. The model captures both first and second order
sensitivities for options. The following table summarizes the
value-at-risk
results for trading and non-trading activities. These results
may vary from time to time as strategies change in trading
activities or hedging levels change in non-trading activities.
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|
|
|
|
|
|
|
|
|
|
Trading
|
|
|
Non-trading
|
|
|
|
Activities
|
|
|
Activities
|
|
|
|
(Millions of dollars)
|
|
|
2007
|
|
|
|
|
|
|
|
|
At December 31
|
|
$
|
10
|
|
|
$
|
72
|
|
Average
|
|
|
12
|
|
|
|
63
|
|
High
|
|
|
13
|
|
|
|
72
|
|
Low
|
|
|
10
|
|
|
|
54
|
|
2006
|
|
|
|
|
|
|
|
|
At December 31
|
|
$
|
17
|
|
|
$
|
62
|
|
Average
|
|
|
20
|
|
|
|
75
|
|
High
|
|
|
22
|
|
|
|
86
|
|
Low
|
|
|
17
|
|
|
|
62
|
|
Non-trading: The Corporations
non-trading activities may include hedging of crude oil and
natural gas production. Futures and swaps are used to fix the
selling prices of a portion of the Corporations future
production and the related gains or losses are an integral part
of the Corporations selling prices. Following is a summary
of the Corporations outstanding crude oil hedges at
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
Brent Crude Oil
|
|
|
|
Average
|
|
|
Thousands of
|
|
Maturity
|
|
Selling Price
|
|
|
Barrels per Day
|
|
|
2008
|
|
$
|
25.56
|
|
|
|
24
|
|
2009
|
|
|
25.54
|
|
|
|
24
|
|
2010
|
|
|
25.78
|
|
|
|
24
|
|
2011
|
|
|
26.37
|
|
|
|
24
|
|
2012
|
|
|
26.90
|
|
|
|
24
|
|
There were no hedges of WTI crude oil or natural gas production
at December 31, 2007. As market conditions change, the
Corporation may adjust its hedge percentages. The Corporation
also markets energy commodities including refined petroleum
products, natural gas and electricity. The Corporation uses
futures, swaps and options to manage the risk in its marketing
activities.
Accumulated other comprehensive income (loss) at
December 31, 2007 includes after-tax unrealized deferred
losses of $1,672 million primarily related to crude oil
contracts used as hedges of exploration and production sales.
The pre-tax amount of deferred hedge losses is reflected in
accounts payable and the related income tax benefits are
recorded as deferred tax assets on the balance sheet.
37
The Corporation uses foreign exchange contracts to reduce its
exposure to fluctuating foreign exchange rates by entering into
forward purchase contracts for both the British pound sterling
and the Danish kroner. At December 31, 2007, the
Corporation had $977 million of notional value foreign
exchange contracts maturing in 2008. The fair value of the
foreign exchange contracts was a payable of $1 million at
December 31, 2007. The change in fair value of the foreign
exchange contracts from a 10% change in exchange rates is
estimated to be approximately $100 million at
December 31, 2007.
The Corporations outstanding debt of $3,980 million
has a fair value of $4,263 million at December 31,
2007. A 15% decrease in the rate of interest would increase the
fair value of debt by approximately $200 million at
December 31, 2007.
Trading: In trading activities, the
Corporation is exposed to changes in crude oil, natural gas and
refined product prices. The trading partnership in which the
Corporation has a 50% voting interest trades energy commodities,
securities and derivatives. The accounts of the partnership are
consolidated with those of the Corporation. The Corporation also
takes trading positions for its own account. The information
that follows represents 100% of the trading partnership and the
Corporations proprietary trading accounts.
Gains or losses from sales of physical products are recorded at
the time of sale. Total realized gains on trading activities for
2007 amounted to $303 million ($721 million in 2006).
Derivative trading transactions are marked-to-market and
unrealized gains or losses are reflected in income currently.
The following table provides an assessment of the factors
affecting the changes in fair value of trading activities and
represents 100% of the trading partnership and other trading
activities.
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Fair value of contracts outstanding at the beginning of the year
|
|
$
|
365
|
|
|
$
|
1,109
|
|
Change in fair value of contracts outstanding at the beginning
of the year and still outstanding at the end of year
|
|
|
193
|
|
|
|
(82
|
)
|
Reversal of fair value for contracts closed during the year
|
|
|
(230
|
)
|
|
|
(547
|
)
|
Fair value of contracts entered into during the year and still
outstanding
|
|
|
(174
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at the end of the year
|
|
$
|
154
|
|
|
$
|
365
|
|
|
|
|
|
|
|
|
|
|
The Corporation uses observable market values for determining
the fair value of its trading instruments. In cases where
actively quoted prices are not available, other external sources
are used which incorporate information about commodity prices in
actively quoted markets, quoted prices in less active markets
and other market fundamental analysis. Internal estimates are
based on internal models incorporating underlying market
information such as commodity volatilities and correlations. The
Corporations risk management department regularly compares
valuations to independent sources and models.
The following table summarizes the sources of fair values of
derivatives used in the Corporations trading activities at
December 31, 2007:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 and
|
|
|
|
Total
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Beyond
|
|
|
|
|
|
|
(Millions of dollars)
|
|
|
|
|
|
Source of fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices actively quoted
|
|
$
|
119
|
|
|
$
|
45
|
|
|
$
|
53
|
|
|
$
|
42
|
|
|
$
|
(21
|
)
|
Other external sources
|
|
|
36
|
|
|
|
24
|
|
|
|
10
|
|
|
|
|
|
|
|
2
|
|
Internal estimates
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
154
|
|
|
$
|
68
|
|
|
$
|
63
|
|
|
$
|
42
|
|
|
$
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
The following table summarizes the net receivables relating to
the Corporations trading activities and the credit ratings
of counterparties at December 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Investment grade determined by outside sources
|
|
$
|
364
|
|
|
$
|
347
|
|
Investment grade determined internally*
|
|
|
173
|
|
|
|
59
|
|
Less than investment grade
|
|
|
55
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
Fair value of net receivables outstanding at the end of the year
|
|
$
|
592
|
|
|
$
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Based on information provided by
counterparties and other available sources. |
39
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
|
|
|
|
|
|
|
Page
|
|
|
|
Number
|
|
|
|
|
|
41
|
|
|
|
|
42
|
|
|
|
|
44
|
|
|
|
|
45
|
|
|
|
|
46
|
|
|
|
|
47
|
|
|
|
|
48
|
|
|
|
|
49
|
|
|
|
|
74
|
|
|
|
|
80
|
|
|
|
|
86
|
|
|
|
|
87
|
|
|
|
|
*
|
|
Schedules other than
Schedule II have been omitted because of the absence of the
conditions under which they are required or because the required
information is presented in the financial statements or the
notes thereto. |
40
Managements
Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term
is defined in Exchange Act
Rules 13a-15(f).
Under the supervision and with the participation of our
management, including our principal executive officer and
principal financial officer, we conducted an evaluation of the
effectiveness of our internal control over financial reporting,
as required by Section 404 of the Sarbanes-Oxley Act, based
on the framework in Internal Control Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on our
evaluation, management concluded that our internal control over
financial reporting was effective as of December 31, 2007.
The Corporations independent registered public accounting
firm, Ernst & Young LLP, has audited the effectiveness
of the Corporations internal control over financial
reporting as of December 31, 2007, as stated in their
report, which is included herein.
|
|
|
|
|
|
|
By
|
|
/s/ John
P. Rielly
John
P. Rielly
Senior Vice President and
Chief Financial Officer
|
|
By
|
|
/s/ John
B. Hess
John
B. Hess
Chairman of the Board and
Chief Executive Officer
|
February 22, 2008
41
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited Hess Corporations internal control over
financial reporting as of December 31, 2007, based on
criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (the COSO criteria). Hess
Corporations management is responsible for maintaining
effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over
financial reporting included in the accompanying
Managements Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the
companys internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Hess Corporation maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2007 based on the COSO criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheet of Hess Corporation and consolidated
subsidiaries as of December 31, 2007 and 2006, and the
related statements of consolidated income, cash flows,
stockholders equity and comprehensive income of Hess
Corporation and consolidated subsidiaries for each of the three
years in the period ended December 31, 2007, and our report
dated February 22, 2008 expressed an unqualified opinion
thereon.
February 22, 2008
New York, New York
42
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited the accompanying consolidated balance sheet of
Hess Corporation and consolidated subsidiaries as of
December 31, 2007 and 2006, and the related statements of
consolidated income, cash flows, stockholders equity and
comprehensive income for each of the three years in the period
ended December 31, 2007. Our audits also included the
Financial Statement Schedule listed in the Index at Item 8.
These financial statements and schedule are the responsibility
of the Corporations management. Our responsibility is to
express an opinion on these financial statements and schedule
based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Hess Corporation and consolidated
subsidiaries at December 31, 2007 and 2006, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2007, in conformity with U.S. generally
accepted accounting principles. Also, in our opinion, the
related Financial Statement Schedule, when considered in
relation to the consolidated financial statements taken as a
whole, presents fairly in all material respects, the information
set forth therein.
As discussed in Note 1 to the consolidated financial
statements, the Corporation adopted FASB Staff Position (FSP)
AUG AIR-1, Accounting for Planned Major Maintenance Activities,
and FASB Interpretation No. 48, Accounting for Uncertainty
in Income Taxes, effective January 1, 2007. As discussed in
Note 10 to the consolidated financial statements, the
Corporation adopted the provisions of Statement of Financial
Accounting Standards No. 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement Plans,
effective December 31, 2006. Also, as discussed in
Note 1 to the consolidated financial statements, the
Corporation adopted Statement of Financial Accounting Standards
No. 123R, Share-Based Payment, effective January 1,
2006.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Hess Corporations internal control over
financial reporting as of December 31, 2007, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 22, 2008
expressed an unqualified opinion thereon.
February 22, 2008
New York, New York
43
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED
BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
|
|
|
|
December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars;
|
|
|
|
thousands of shares)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
607
|
|
|
$
|
383
|
|
Accounts receivable
|
|
|
|
|
|
|
|
|
Trade
|
|
|
4,527
|
|
|
|
3,659
|
|
Other
|
|
|
181
|
|
|
|
214
|
|
Inventories
|
|
|
1,250
|
|
|
|
1,005
|
|
Other current assets
|
|
|
361
|
|
|
|
587
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
6,926
|
|
|
|
5,848
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS IN AFFILIATES
|
|
|
|
|
|
|
|
|
HOVENSA L.L.C.
|
|
|
933
|
|
|
|
1,055
|
|
Other
|
|
|
184
|
|
|
|
188
|
|
|
|
|
|
|
|
|
|
|
Total investments in affiliates
|
|
|
1,117
|
|
|
|
1,243
|
|
|
|
|
|
|
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Exploration and Production
|
|
|
22,903
|
|
|
|
20,199
|
|
Marketing, Refining and Corporate
|
|
|
1,928
|
|
|
|
1,781
|
|
|
|
|
|
|
|
|
|
|
Total at cost
|
|
|
24,831
|
|
|
|
21,980
|
|
Less reserves for depreciation, depletion, amortization and
lease impairment
|
|
|
10,197
|
|
|
|
9,672
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment net
|
|
|
14,634
|
|
|
|
12,308
|
|
|
|
|
|
|
|
|
|
|
GOODWILL
|
|
|
1,225
|
|
|
|
1,253
|
|
DEFERRED INCOME TAXES
|
|
|
1,873
|
|
|
|
1,430
|
|
OTHER ASSETS
|
|
|
356
|
|
|
|
360
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
26,131
|
|
|
$
|
22,442
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,741
|
|
|
$
|
4,803
|
|
Accrued liabilities
|
|
|
1,638
|
|
|
|
1,477
|
|
Taxes payable
|
|
|
583
|
|
|
|
432
|
|
Current maturities of long-term debt
|
|
|
62
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
8,024
|
|
|
|
6,739
|
|
LONG-TERM DEBT
|
|
|
3,918
|
|
|
|
3,745
|
|
DEFERRED INCOME TAXES
|
|
|
2,362
|
|
|
|
2,116
|
|
ASSET RETIREMENT OBLIGATIONS
|
|
|
1,016
|
|
|
|
824
|
|
OTHER LIABILITIES AND DEFERRED CREDITS
|
|
|
1,037
|
|
|
|
871
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
16,357
|
|
|
|
14,295
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
Preferred stock, par value $1.00, 20,000 shares authorized
|
|
|
|
|
|
|
|
|
3% cumulative convertible series
|
|
|
|
|
|
|
|
|
Authorized 330 shares
|
|
|
|
|
|
|
|
|
Issued 284 shares in 2007 ($14 million
liquidation preference) and 324 shares in 2006
|
|
|
|
|
|
|
|
|
Common stock, par value $1.00
|
|
|
|
|
|
|
|
|
Authorized 600,000 shares
|
|
|
|
|
|
|
|
|
Issued 320,600 shares in 2007;
315,018 shares in 2006
|
|
|
321
|
|
|
|
315
|
|
Capital in excess of par value
|
|
|
1,882
|
|
|
|
1,689
|
|
Retained earnings
|
|
|
9,412
|
|
|
|
7,707
|
|
Accumulated other comprehensive income (loss)
|
|
|
(1,841
|
)
|
|
|
(1,564
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
9,774
|
|
|
|
8,147
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
|
|
$
|
26,131
|
|
|
$
|
22,442
|
|
|
|
|
|
|
|
|
|
|
The consolidated financial statements reflect the successful
efforts method of accounting for oil and gas exploration and
production activities.
See accompanying notes to consolidated financial statements.
44
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT
OF CONSOLIDATED INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
|
|
|
|
December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions, except per share data)
|
|
|
REVENUES AND NON-OPERATING INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (excluding excise taxes) and other operating revenues
|
|
$
|
31,647
|
|
|
$
|
28,067
|
|
|
$
|
22,747
|
|
Equity in income of HOVENSA L.L.C.
|
|
|
176
|
|
|
|
201
|
|
|
|
370
|
|
Gain on asset sales
|
|
|
21
|
|
|
|
369
|
|
|
|
48
|
|
Other income, net
|
|
|
80
|
|
|
|
81
|
|
|
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues and non-operating income
|
|
|
31,924
|
|
|
|
28,718
|
|
|
|
23,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of products sold (excluding items shown separately below)
|
|
|
22,573
|
|
|
|
19,912
|
|
|
|
17,041
|
|
Production expenses
|
|
|
1,581
|
|
|
|
1,250
|
|
|
|
1,007
|
|
Marketing expenses
|
|
|
944
|
|
|
|
940
|
|
|
|
842
|
|
Exploration expenses, including dry holes and lease impairment
|
|
|
515
|
|
|
|
552
|
|
|
|
397
|
|
Other operating expenses
|
|
|
161
|
|
|
|
122
|
|
|
|
155
|
|
General and administrative expenses
|
|
|
614
|
|
|
|
471
|
|
|
|
357
|
|
Interest expense
|
|
|
256
|
|
|
|
201
|
|
|
|
224
|
|
Depreciation, depletion and amortization
|
|
|
1,576
|
|
|
|
1,224
|
|
|
|
1,025
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
28,220
|
|
|
|
24,672
|
|
|
|
21,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
3,704
|
|
|
|
4,046
|
|
|
|
2,201
|
|
Provision for income taxes
|
|
|
1,872
|
|
|
|
2,126
|
|
|
|
975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
1,832
|
|
|
$
|
1,920
|
|
|
$
|
1,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less preferred stock dividends
|
|
|
|
|
|
|
44
|
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME APPLICABLE TO COMMON SHAREHOLDERS
|
|
$
|
1,832
|
|
|
$
|
1,876
|
|
|
$
|
1,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC NET INCOME PER SHARE
|
|
$
|
5.86
|
|
|
$
|
6.75
|
|
|
$
|
4.32
|
|
DILUTED NET INCOME PER SHARE
|
|
$
|
5.74
|
|
|
$
|
6.08
|
|
|
$
|
3.93
|
|
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
(DILUTED)
|
|
|
319.3
|
|
|
|
315.7
|
|
|
|
312.1
|
|
See accompanying notes to consolidated financial statements.
45
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT
OF CONSOLIDATED CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
|
|
|
|
December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,832
|
|
|
$
|
1,920
|
|
|
$
|
1,226
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,576
|
|
|
|
1,224
|
|
|
|
1,025
|
|
Exploratory dry hole costs
|
|
|
65
|
|
|
|
241
|
|
|
|
170
|
|
Lease impairment
|
|
|
102
|
|
|
|
99
|
|
|
|
78
|
|
Pre-tax gain on asset sales
|
|
|
(21
|
)
|
|
|
(369
|
)
|
|
|
(48
|
)
|
Provision (benefit) for deferred income taxes
|
|
|
(33
|
)
|
|
|
281
|
|
|
|
(98
|
)
|
Distributed (undistributed) earnings of HOVENSA L.L.C., net
|
|
|
124
|
|
|
|
199
|
|
|
|
(114
|
)
|
Changes in other operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in accounts receivable
|
|
|
(783
|
)
|
|
|
(179
|
)
|
|
|
(1,042
|
)
|
Increase in inventories
|
|
|
(254
|
)
|
|
|
(152
|
)
|
|
|
(270
|
)
|
Increase (decrease) in accounts payable and accrued liabilities
|
|
|
597
|
|
|
|
(44
|
)
|
|
|
877
|
|
Increase (decrease) in taxes payable
|
|
|
134
|
|
|
|
47
|
|
|
|
(111
|
)
|
Changes in other assets and liabilities
|
|
|
168
|
|
|
|
224
|
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
3,507
|
|
|
|
3,491
|
|
|
|
1,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(3,578
|
)
|
|
|
(3,844
|
)
|
|
|
(2,341
|
)
|
Proceeds from asset sales
|
|
|
93
|
|
|
|
444
|
|
|
|
74
|
|
Payments received on notes receivable
|
|
|
61
|
|
|
|
76
|
|
|
|
60
|
|
Other
|
|
|
(50
|
)
|
|
|
35
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(3,474
|
)
|
|
|
(3,289
|
)
|
|
|
(2,255
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt with maturities of greater than 90 days
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings
|
|
|
1,094
|
|
|
|
320
|
|
|
|
600
|
|
Repayments
|
|
|
(886
|
)
|
|
|
(333
|
)
|
|
|
(650
|
)
|
Cash dividends paid
|
|
|
(127
|
)
|
|
|
(161
|
)
|
|
|
(159
|
)
|
Employee stock options exercised
|
|
|
110
|
|
|
|
40
|
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
191
|
|
|
|
(134
|
)
|
|
|
(147
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
|
224
|
|
|
|
68
|
|
|
|
(562
|
)
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
|
|
383
|
|
|
|
315
|
|
|
|
877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
607
|
|
|
$
|
383
|
|
|
$
|
315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
46
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT
OF CONSOLIDATED STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
|
(Millions of dollars; thousands of shares)
|
|
|
PREFERRED STOCK
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
324
|
|
|
$
|
|
|
|
|
13,824
|
|
|
$
|
14
|
|
|
|
13,827
|
|
|
$
|
14
|
|
Conversion of preferred stock to common stock
|
|
|
(40
|
)
|
|
|
|
|
|
|
(13,500
|
)
|
|
|
(14
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
284
|
|
|
|
|
|
|
|
324
|
|
|
|
|
|
|
|
13,824
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMON STOCK
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
315,018
|
|
|
|
315
|
|
|
|
279,197
|
|
|
|
279
|
|
|
|
275,145
|
|
|
|
275
|
|
Activity related to restricted common stock awards, net
|
|
|
941
|
|
|
|
1
|
|
|
|
903
|
|
|
|
1
|
|
|
|
948
|
|
|
|
1
|
|
Employee stock options exercised
|
|
|
4,566
|
|
|
|
5
|
|
|
|
1,283
|
|
|
|
1
|
|
|
|
3,098
|
|
|
|
3
|
|
Conversion of preferred stock to common stock
|
|
|
75
|
|
|
|
|
|
|
|
33,635
|
|
|
|
34
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
320,600
|
|
|
|
321
|
|
|
|
315,018
|
|
|
|
315
|
|
|
|
279,197
|
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITAL IN EXCESS OF PAR VALUE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
|
|
|
|
1,689
|
|
|
|
|
|
|
|
1,656
|
|
|
|
|
|
|
|
1,544
|
|
Activity related to restricted common stock awards, net
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
37
|
|
Employee stock options exercised, including income tax benefits
|
|
|
|
|
|
|
143
|
|
|
|
|
|
|
|
68
|
|
|
|
|
|
|
|
75
|
|
Conversion of preferred stock to common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
Reclassification resulting from adoption of FAS 123R
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
|
|
|
|
1,882
|
|
|
|
|
|
|
|
1,689
|
|
|
|
|
|
|
|
1,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RETAINED EARNINGS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
|
|
|
|
7,707
|
|
|
|
|
|
|
|
5,946
|
|
|
|
|
|
|
|
4,879
|
|
Net income
|
|
|
|
|
|
|
1,832
|
|
|
|
|
|
|
|
1,920
|
|
|
|
|
|
|
|
1,226
|
|
Dividends declared on common stock
|
|
|
|
|
|
|
(127
|
)
|
|
|
|
|
|
|
(115
|
)
|
|
|
|
|
|
|
(111
|
)
|
Dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44
|
)
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
|
|
|
|
9,412
|
|
|
|
|
|
|
|
7,707
|
|
|
|
|
|
|
|
5,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
|
|
|
|
(1,564
|
)
|
|
|
|
|
|
|
(1,526
|
)
|
|
|
|
|
|
|
(1,024
|
)
|
Net other comprehensive income (loss)
|
|
|
|
|
|
|
(277
|
)
|
|
|
|
|
|
|
104
|
|
|
|
|
|
|
|
(502
|
)
|
Cumulative effect of adoption of FAS 158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
|
|
|
|
(1,841
|
)
|
|
|
|
|
|
|
(1,564
|
)
|
|
|
|
|
|
|
(1,526
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED COMPENSATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51
|
)
|
|
|
|
|
|
|
(43
|
)
|
Change in unearned compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
Reclassification resulting from adoption of FAS 123R
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL STOCKHOLDERS EQUITY at December 31
|
|
|
|
|
|
$
|
9,774
|
|
|
|
|
|
|
$
|
8,147
|
|
|
|
|
|
|
$
|
6,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
47
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT
OF CONSOLIDATED COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
|
|
|
|
December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
COMPONENTS OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,832
|
|
|
$
|
1,920
|
|
|
$
|
1,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gains (losses) on cash flow hedges, after tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of hedge losses recognized in income
|
|
|
325
|
|
|
|
345
|
|
|
|
946
|
|
Net change in fair value of cash flow hedges
|
|
|
(659
|
)
|
|
|
(379
|
)
|
|
|
(1,381
|
)
|
Change in minimum postretirement plan liabilities, after tax
|
|
|
17
|
|
|
|
90
|
|
|
|
(33
|
)
|
Change in foreign currency translation adjustment and other
|
|
|
40
|
|
|
|
48
|
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net other comprehensive income (loss)
|
|
|
(277
|
)
|
|
|
104
|
|
|
|
(502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
$
|
1,555
|
|
|
$
|
2,024
|
|
|
$
|
724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
48
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
1.
|
Summary
of Significant Accounting Policies
|
Nature of Business: Hess Corporation
and subsidiaries (the Corporation) engage in the exploration for
and the development, production, purchase, transportation and
sale of crude oil and natural gas. These activities are
conducted principally in Algeria, Australia, Azerbaijan, Brazil,
Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia,
Libya, Malaysia, Norway, Russia, Thailand, the United Kingdom
and the United States. In addition, the Corporation
manufactures, purchases, transports, trades and markets refined
petroleum and other energy products. The Corporation owns 50% of
HOVENSA L.L.C. (HOVENSA), a refinery joint venture in the United
States Virgin Islands. An additional refining facility,
terminals and retail gasoline stations, most of which include
convenience stores, are located on the East Coast of the United
States.
In preparing financial statements in conformity with
U.S. generally accepted accounting principles (GAAP),
management makes estimates and assumptions that affect the
reported amounts of assets and liabilities in the balance sheet
and revenues and expenses in the income statement. Actual
results could differ from those estimates. Among the estimates
made by management are oil and gas reserves, asset valuations,
depreciable lives, pension liabilities, legal and environmental
obligations, asset retirement obligations and income taxes.
Principles of Consolidation: The
consolidated financial statements include the accounts of Hess
Corporation and entities in which the Corporation owns more than
a 50% voting interest or entities that the Corporation controls.
The Corporations undivided interests in unincorporated oil
and gas exploration and production ventures are proportionately
consolidated.
Investments in affiliated companies, 20% to 50% owned, including
HOVENSA, are stated at cost of acquisition plus the
Corporations equity in undistributed net income since
acquisition. The Corporation consolidates the trading
partnership in which it owns a 50% voting interest and over
which it exercises control.
Intercompany transactions and accounts are eliminated in
consolidation.
Revenue Recognition: The Corporation
recognizes revenues from the sale of crude oil, natural gas,
petroleum products and other merchandise when title passes to
the customer. Sales are reported net of excise and similar taxes
in the consolidated statement of income. The Corporation
recognizes revenues from the production of natural gas
properties based on sales to customers. Differences between
natural gas volumes sold and the Corporations share of
natural gas production are not material. Revenues from natural
gas and electricity sales by the Corporations marketing
operations are recognized based on meter readings and estimated
deliveries to customers since the last meter reading.
In its exploration and production activities, the Corporation
enters into crude oil purchase and sale transactions with the
same counterparty that are entered into in contemplation of one
another for the primary purpose of changing location or quality.
Similarly, in its marketing activities, the Corporation also
enters into refined product purchase and sale transactions with
the same counterparty. These arrangements are reported net in
sales and other operating revenues in the consolidated statement
of income.
Derivatives: The Corporation utilizes
derivative instruments for both non-trading and trading
activities. In non-trading activities, the Corporation uses
futures, forwards, options and swaps, individually or in
combination, to mitigate its exposure to fluctuations in prices
of crude oil, natural gas, refined products and electricity, and
changes in foreign currency exchange rates. In trading
activities, the Corporation, principally through a consolidated
partnership, trades energy commodities derivatives, including
futures, forwards, options and swaps based on expectations of
future market conditions.
All derivative instruments are recorded at fair value in the
Corporations balance sheet. The Corporations policy
for recognizing the changes in fair value of derivatives varies
based on the designation of the derivative. The changes in fair
value of derivatives that are not designated as hedges under
FAS No. 133 are recognized currently in earnings.
Derivatives may be designated as hedges of expected future cash
flows or forecasted transactions (cash flow hedges) or hedges of
firm commitments (fair value hedges). The effective portion of
changes in fair value of
49
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
derivatives that are designated as cash flow hedges is recorded
as a component of other comprehensive income (loss). Amounts
included in accumulated other comprehensive income (loss) for
cash flow hedges are reclassified into earnings in the same
period that the hedged item is recognized in earnings. The
ineffective portion of changes in fair value of derivatives
designated as cash flow hedges is recorded currently in
earnings. Changes in fair value of derivatives designated as
fair value hedges are recognized currently in earnings. The
change in fair value of the related hedged commitment is
recorded as an adjustment to its carrying amount and recognized
currently in earnings.
Cash and Cash Equivalents: Cash
equivalents consist of highly liquid investments, which are
readily convertible into cash and have maturities of three
months or less when acquired.
Inventories: Inventories are valued at
the lower of cost or market. For refined product inventories
valued at cost, the Corporation uses principally the
last-in,
first-out (LIFO) inventory method. For the remaining
inventories, cost is generally determined using average actual
costs.
Exploration and Development
Costs: Exploration and production activities
are accounted for using the successful efforts method. Costs of
acquiring unproved and proved oil and gas leasehold acreage,
including lease bonuses, brokers fees and other related
costs, are capitalized. Annual lease rentals, exploration
expenses and exploratory dry hole costs are expensed as
incurred. Costs of drilling and equipping productive wells,
including development dry holes, and related production
facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves
are capitalized pending determination of whether proved reserves
have been found. In accordance with Financial Accounting
Standards Board (FASB) Staff Position
19-1,
Accounting for Suspended Well Costs, which amended
FAS No. 19, Financial Accounting and Reporting by
Oil and Gas Producing Companies (FAS No. 19),
exploratory drilling costs remain capitalized after drilling is
completed if (1) the well has found a sufficient quantity
of reserves to justify completion as a producing well and
(2) sufficient progress is being made in assessing the
reserves and the economic and operating viability of the
project. If either of those criteria is not met, or if there is
substantial doubt about the economic or operational viability of
a project, the capitalized well costs are charged to expense.
Indicators of sufficient progress in assessing reserves and the
economic and operating viability of a project include commitment
of project personnel, active negotiations for sales contracts
with customers, negotiations with governments, operators and
contractors, firm plans for additional drilling and other
factors.
Depreciation, Depletion and
Amortization: The Corporation records
depletion expense for acquisition costs of proved properties
using the units of production method over proved oil and gas
reserves. Depreciation and depletion expense for oil and gas
production equipment and wells is calculated using the units of
production method over proved developed oil and gas reserves.
Depreciation of all other plant and equipment is determined on
the straight-line method based on estimated useful lives. Retail
gas stations and equipment related to a leased property, are
depreciated over the estimated useful lives not to exceed the
remaining lease period. Provisions for impairment of undeveloped
oil and gas leases are based on periodic evaluations and other
factors.
Capitalized Interest: Interest from
external borrowings is capitalized on material projects using
the weighted average cost of outstanding borrowings until the
project is substantially complete and ready for its intended
use, which for oil and gas assets is at first production from
the field. Capitalized interest is depreciated over the useful
lives of the assets in the same manner as the depreciation of
the underlying assets.
Asset Retirement Obligations: The
Corporation has material legal obligations to remove and
dismantle long lived assets and to restore land or seabed at
certain exploration and production locations. The Corporation
accounts for asset retirement obligations as required by
FAS No. 143, Accounting for Asset Retirement
Obligations and FASB Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations.
Under these standards, a liability is recognized for the
fair value of legally required asset retirement obligations
associated with long-lived assets in the period in which the
retirement obligations are incurred. In addition, the fair value
of any legally required conditional
50
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
asset retirement obligations is recorded if the liability can be
reasonably estimated. The Corporation capitalizes the associated
asset retirement costs as part of the carrying amount of the
long-lived assets.
Impairment of Long-Lived Assets: The
Corporation reviews long-lived assets, including oil and gas
properties at a field level, for impairment whenever events or
changes in circumstances indicate that the carrying amounts may
not be recovered. If the carrying amounts are not expected to be
recovered by undiscounted future cash flows, the assets are
impaired and an impairment loss is recorded. The amount of
impairment is based on the estimated fair value of the assets
generally determined by discounting anticipated future net cash
flows. In the case of oil and gas fields, the net present value
of future cash flows is based on managements best estimate
of future prices, which is determined with reference to recent
historical prices and published forward prices, applied to
projected production volumes of individual fields and discounted
at a rate commensurate with the risks involved. The projected
production volumes represent reserves, including probable
reserves, expected to be produced based on a stipulated amount
of capital expenditures. The production volumes, prices and
timing of production are consistent with internal projections
and other externally reported information. Oil and gas prices
used for determining asset impairments will generally differ
from the year-end prices used in the standardized measure of
discounted future net cash flows.
Impairment of Equity Investees: The
Corporation reviews equity method investments for impairment
whenever events or changes in circumstances indicate that an
other than temporary decline in value has occurred. The amount
of the impairment is based on quoted market prices, where
available, or other valuation techniques.
Impairment of Goodwill: In accordance
with FAS No. 142, Goodwill and Other Intangible
Assets, goodwill is not amortized; however, it is tested for
impairment annually in the fourth quarter. This impairment test
is calculated at the reporting unit level, which is the
Exploration and Production operating segment for the
Corporations goodwill. The Corporation identifies
potential impairments by comparing the fair value of the
reporting unit to its book value, including goodwill. If the
fair value of the reporting unit exceeds the carrying amount,
goodwill is not impaired. If the carrying value exceeds the fair
value, the Corporation calculates the possible impairment loss
by comparing the implied fair value of goodwill with the
carrying amount. If the implied fair value of goodwill is less
than the carrying amount, an impairment would be recorded.
Maintenance and Repairs: Maintenance
and repairs are expensed as incurred, including costs of
refinery turnarounds. Capital improvements are recorded as
additions in property, plant and equipment.
Effective January 1, 2007, the Corporation adopted
Financial Accounting Standards Board (FASB) Staff Position (FSP)
AUG AIR-1, Accounting for Planned Major Maintenance
Activities. This FSP eliminated the previously acceptable
accrue-in-advance
method of accounting for planned major maintenance. As required,
the Corporation retrospectively applied the provisions of this
FSP which resulted in a change of its method of accounting to
recognize expenses associated with refinery turnarounds when
such costs are incurred. The impact of adopting this FSP
increased previously reported 2006 earnings by $4 million
($.01 per diluted share). In addition, previously reported
2005 net income decreased by $16 million ($.05 per
diluted share) and retained earnings as of January 1, 2005
increased by approximately $48 million. All prior period
amounts in the consolidated financial statements and
accompanying notes reflect this retrospective accounting change.
Environmental Expenditures: The
Corporation accrues and expenses environmental costs to
remediate existing conditions related to past operations when
the future costs are probable and reasonably estimable. The
Corporation capitalizes environmental expenditures that increase
the life or efficiency of property or that reduce or prevent
future adverse impacts to the environment.
Share-Based Compensation: All
share-based compensation is expensed and recognized on a
straight-line basis over the vesting period of the awards. Prior
to the adoption of FAS No. 123R, Share-Based
Payment, on January 1, 2006, the Corporation recorded
compensation expense for restricted common stock awards and used
the intrinsic value method to account for employee stock
options. The Corporation used the modified prospective
application method for its adoption of FAS No. 123R,
which requires that compensation cost be recorded for
51
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
restricted stock, previously awarded unvested stock options
outstanding at January 1, 2006 based on the grant date
fair-values used for disclosure purposes under previous
accounting requirements, and stock options awarded subsequent to
January 1, 2006 determined under the provisions of
FAS No. 123R.
Income Taxes: Deferred income taxes are
determined using the liability method. The Corporation regularly
assesses the realizability of deferred tax assets, based on
estimates of future taxable income, the availability of tax
planning strategies, the existence of appreciated assets, the
available carryforward periods for net operating losses and
other factors.
The Corporation adopted the provisions of FASB Interpretation
No. 48 (FIN-48) on January 1, 2007. The impact of
adoption was not material to the Corporations financial
position, results of operations or cash flows. A deferred tax
asset of $28 million related to an acquired net operating
loss carryforward was recorded in accordance with FIN 48
and goodwill was reduced. In addition, effective with its
adoption of FIN-48, the Corporation recognizes the financial
statement effect of a tax position only when management believes
that it is more likely than not, that based on the technical
merits, the position will be sustained upon examination. The
Corporation does not provide for deferred U.S. income taxes
applicable to undistributed earnings of foreign subsidiaries
that are indefinitely reinvested in foreign operations. The
Corporation classifies interest and penalties associated with
uncertain tax positions as income tax expense.
Foreign Currency Translation: The
U.S. dollar is the functional currency (primary currency in
which business is conducted) for most foreign operations.
Adjustments resulting from translating monetary assets and
liabilities that are denominated in a nonfunctional currency
into the functional currency are recorded in other income. For
operations that do not use the U.S. dollar as the
functional currency, adjustments resulting from translating
foreign currency assets and liabilities into U.S. dollars
are recorded in a separate component of stockholders
equity titled accumulated other comprehensive income (loss).
Recently Issued Accounting Standard: In
September 2006, the FASB issued FAS No. 157, Fair
Value Measurements (FAS No. 157).
FAS No. 157 establishes a framework for measuring fair
value and requires disclosure of a fair value hierarchy, which
applies to financial assets and liabilities measured at fair
value under other authoritative accounting pronouncements. The
standard also requires additional disclosure about the methods
of determining fair value. The Corporation as required, will
prospectively adopt the provisions of FAS No. 157
effective January 1, 2008. The Corporation believes that
the impact of adopting FAS No. 157 on net income will
not be material. In addition, the Corporation expects to record
a reduction in the charge reflected in accumulated other
comprehensive income relating to the Corporations crude
oil hedging program of approximately $160 million, after
income taxes.
|
|
2.
|
Acquisitions
and Divestitures
|
2007: In February 2007, the Corporation
completed the acquisition of a 28% interest in the Genghis Khan
oil and gas development located in the deepwater Gulf of Mexico
on Green Canyon Blocks 652 and 608 for $371 million,
of which $342 million was allocated to proved and unproved
properties and the remainder to wells and equipment. The Genghis
Khan development is part of the same geologic structure as the
Shenzi development. This transaction was accounted for as an
acquisition of assets.
During the second quarter of 2007, the Corporation completed the
sale of its interests in the Scott and Telford fields located in
the United Kingdom for $93 million and recorded a gain of
$21 million ($15 million after income taxes). At the
time of sale, these two fields were producing at a combined net
rate of 6,500 barrels of oil per day.
2006: In January 2006, the Corporation,
in conjunction with its Oasis Group partners, re-entered its
former oil and gas production operations in the Waha concessions
in Libya, in which the Corporation holds an 8.16% interest. The
re-entry terms included a
25-year
extension of the concessions and payments by the Corporation to
the Libyan National Oil Corporation of $359 million. This
transaction was accounted for as a business combination.
52
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the allocation of the purchase
price to assets and liabilities acquired (in millions):
|
|
|
|
|
Property, plant and equipment
|
|
$
|
362
|
|
Goodwill
|
|
|
236
|
|
|
|
|
|
|
Total assets acquired
|
|
|
598
|
|
Current liabilities
|
|
|
(3
|
)
|
Deferred tax liabilities
|
|
|
(236
|
)
|
|
|
|
|
|
Net assets acquired
|
|
$
|
359
|
|
|
|
|
|
|
The goodwill recorded in this transaction relates to the
deferred tax liability recorded for the difference in book and
tax bases of the assets acquired. The goodwill is not expected
to be deductible for income tax purposes. The primary reason for
the Libyan investment was to acquire long-lived crude oil
reserves.
The Corporation acquired a 55% working interest in the deepwater
section of the West Mediterranean Block 1 Concession (the
West Med Block) in Egypt for $413 million. The Corporation
has a
25-year
development lease for the West Med Block, which contains four
existing natural gas discoveries and additional exploration
opportunities. This transaction was accounted for as an
acquisition of assets.
In the first quarter of 2006, the Corporation completed the sale
of its interests in certain oil and gas producing properties
located in the Permian Basin in Texas and New Mexico for
$358 million. This asset sale resulted in an after-tax gain
of $186 million ($289 million before income taxes).
These assets were producing at a combined net rate of
approximately 5,500 barrels of oil equivalent per day at
the time of sale. In June 2006, the Corporation also completed
the sale of certain U.S. Gulf Coast onshore oil and gas
producing assets for $86 million, resulting in an after-tax
gain of $50 million ($80 million before income taxes).
These assets were producing at a combined net rate of
approximately 2,600 barrels of oil equivalent per day at
the time of sale.
Inventories at December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Crude oil and other charge stocks
|
|
$
|
338
|
|
|
$
|
202
|
|
Refined products and natural gas
|
|
|
1,577
|
|
|
|
1,185
|
|
Less: LIFO adjustment
|
|
|
(1,029
|
)
|
|
|
(676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
886
|
|
|
|
711
|
|
Merchandise, materials and supplies
|
|
|
364
|
|
|
|
294
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,250
|
|
|
$
|
1,005
|
|
|
|
|
|
|
|
|
|
|
The percentage of LIFO inventory to total crude oil, refined
products and natural gas inventories was 69% and 66% at
December 31, 2007 and 2006, respectively. During 2007 and
2005 the Corporation reduced LIFO inventories, which are carried
at lower costs than current inventory costs. The effect of the
LIFO inventory liquidations was to decrease cost of products
sold by approximately $38 million in 2007 ($24 million
after income taxes) and $51 million in 2005
($32 million after income taxes).
53
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
4.
|
Refining
Joint Venture
|
The Corporation has an investment in HOVENSA L.L.C., a 50% joint
venture with Petroleos de Venezuela, S.A. (PDVSA), which is
accounted for using the equity method. HOVENSA owns and operates
a refinery in the U.S. Virgin Islands. Summarized financial
information for HOVENSA as of December 31 and for the years then
ended follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Summarized Balance Sheet, at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
279
|
|
|
$
|
290
|
|
|
$
|
612
|
|
Short-term investments
|
|
|
|
|
|
|
|
|
|
|
263
|
|
Other current assets
|
|
|
1,183
|
|
|
|
943
|
|
|
|
814
|
|
Net fixed assets
|
|
|
2,181
|
|
|
|
2,123
|
|
|
|
1,950
|
|
Other assets
|
|
|
62
|
|
|
|
32
|
|
|
|
39
|
|
Current liabilities
|
|
|
(1,459
|
)
|
|
|
(1,013
|
)
|
|
|
(919
|
)
|
Long-term debt
|
|
|
(356
|
)
|
|
|
(252
|
)
|
|
|
(252
|
)
|
Deferred liabilities and credits
|
|
|
(75
|
)
|
|
|
(70
|
)
|
|
|
(44
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners equity
|
|
$
|
1,815
|
|
|
$
|
2,053
|
|
|
$
|
2,463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summarized Income Statement, for the Years Ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
13,396
|
|
|
$
|
11,788
|
|
|
$
|
10,439
|
|
Costs and expenses
|
|
|
(13,039
|
)
|
|
|
(11,381
|
)
|
|
|
(9,694
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
357
|
|
|
$
|
407
|
|
|
$
|
745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hess Corporations share*
|
|
$
|
176
|
|
|
$
|
201
|
|
|
$
|
370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summarized Cash Flow Statement, for the Years Ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
654
|
|
|
$
|
484
|
|
|
$
|
1,070
|
|
Investing activities
|
|
|
(165
|
)
|
|
|
(10
|
)
|
|
|
(426
|
)
|
Financing activities
|
|
|
(500
|
)
|
|
|
(796
|
)
|
|
|
(550
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
(11
|
)
|
|
$
|
(322
|
)
|
|
$
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Before Virgin Islands income
taxes, which were recorded in the Corporations income tax
provision. |
The Corporation received cash distributions from HOVENSA of
$300 million, $400 million and $275 million
during 2007, 2006 and 2005, respectively. The Corporations
share of HOVENSAs undistributed income aggregated
$220 million at December 31, 2007.
The Corporation guarantees the payment of up to 50% of the value
of HOVENSAs crude oil purchases from suppliers other than
PDVSA. The guarantee amounted to $277 million at
December 31, 2007. This amount fluctuates based on the
volume of crude oil purchased and the related crude oil prices.
In addition, the Corporation has agreed to provide funding up to
a current maximum of $15 million to the extent HOVENSA does
not have funds to meet its senior debt obligations.
At formation of the joint venture in 1999, PDVSA V.I., a
wholly-owned subsidiary of PDVSA, purchased a 50% interest in
the fixed assets of the Corporations Virgin Islands
refinery for $62.5 million in cash and a
10-year note
from PDVSA V.I. for $562.5 million bearing interest at
8.46% per annum and requiring principal payments
54
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
over its term. The principal balance of the note, which is due
to be fully repaid by February 2009, was $76 million and
$137 million at December 31, 2007 and 2006,
respectively.
|
|
5.
|
Property,
Plant and Equipment
|
Property, plant and equipment at December 31 consists of the
following:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Exploration and Production
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
1,688
|
|
|
$
|
1,231
|
|
Proved properties
|
|
|
3,350
|
|
|
|
3,298
|
|
Wells, equipment and related facilities
|
|
|
17,865
|
|
|
|
15,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,903
|
|
|
|
20,199
|
|
Marketing, Refining and Corporate
|
|
|
1,928
|
|
|
|
1,781
|
|
|
|
|
|
|
|
|
|
|
Total at cost
|
|
|
24,831
|
|
|
|
21,980
|
|
Less reserves for depreciation, depletion, amortization and
lease impairment
|
|
|
10,197
|
|
|
|
9,672
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment net
|
|
$
|
14,634
|
|
|
$
|
12,308
|
|
|
|
|
|
|
|
|
|
|
In the fourth quarter of 2007 the Corporation recorded asset
impairments at two mature fields in the United Kingdom North
Sea. The pre-tax amount of this charge was $112 million
($56 million after income taxes) and is reflected in
depreciation, depletion and amortization.
The following table discloses the amount of capitalized
exploratory well costs pending determination of proved reserves
at December 31, and the changes therein during the
respective years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Millions of dollars)
|
|
|
Beginning balance at January 1
|
|
$
|
399
|
|
|
$
|
244
|
|
|
$
|
220
|
|
Additions to capitalized exploratory well costs pending the
determination of proved reserves
|
|
|
229
|
|
|
|
299
|
|
|
|
97
|
|
Reclassifications to wells, facilities, and equipment based on
the determination of proved reserves
|
|
|
(20
|
)
|
|
|
(144
|
)
|
|
|
(12
|
)
|
Capitalized exploratory well costs charged to expense
|
|
|
|
|
|
|
|
|
|
|
(61
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance at December 31
|
|
$
|
608
|
|
|
$
|
399
|
|
|
$
|
244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of wells at end of year
|
|
|
30
|
|
|
|
28
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The preceding table excludes exploratory dry hole costs of
$65 million, $241 million and $109 million in
2007, 2006 and 2005, respectively, which were incurred and
subsequently expensed in the same year.
At December 31, 2007, expenditures related to exploratory
drilling costs in excess of one year old were capitalized as
follows (in millions):
|
|
|
|
|
2003
|
|
$
|
46
|
|
2004
|
|
|
8
|
|
2005
|
|
|
17
|
|
2006
|
|
|
233
|
|
|
|
|
|
|
|
|
$
|
304
|
|
|
|
|
|
|
The capitalized well costs in excess of one year relate to 11
projects. Approximately 70% of the costs relates to two projects
in the deepwater Gulf of Mexico where appraisal wells were being
drilled at December 31, 2007. The
55
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
remainder of the costs relate to projects where appraisal and
development activities are ongoing or natural gas sales
contracts are being actively pursued.
|
|
6.
|
Asset
Retirement Obligations
|
The following table describes changes to the Corporations
asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Asset retirement obligations at January 1
|
|
$
|
882
|
|
|
$
|
564
|
|
Liabilities incurred
|
|
|
62
|
|
|
|
16
|
|
Liabilities settled or disposed of
|
|
|
(51
|
)
|
|
|
(60
|
)
|
Accretion expense
|
|
|
50
|
|
|
|
44
|
|
Revisions
|
|
|
84
|
|
|
|
282
|
|
Foreign currency translation
|
|
|
28
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at December 31
|
|
|
1,055
|
|
|
|
882
|
|
Less: current obligations
|
|
|
39
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
Long-term obligations at December 31
|
|
$
|
1,016
|
|
|
$
|
824
|
|
|
|
|
|
|
|
|
|
|
Revisions are primarily attributable to higher service and
equipment costs in the oil and gas industry.
Long-term debt at December 31 consists of the following:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Revolving credit facility, weighted average rate 6.3%
|
|
$
|
220
|
|
|
$
|
300
|
|
Asset-backed credit facility, weighted average rate 5.6%
|
|
|
250
|
|
|
|
318
|
|
Short-term credit facilities, weighted average rate 5.5%
|
|
|
350
|
|
|
|
|
|
Fixed rate debentures:
|
|
|
|
|
|
|
|
|
7.4% due 2009
|
|
|
103
|
|
|
|
103
|
|
6.7% due 2011
|
|
|
662
|
|
|
|
662
|
|
7.9% due 2029
|
|
|
694
|
|
|
|
693
|
|
7.3% due 2031
|
|
|
745
|
|
|
|
745
|
|
7.1% due 2033
|
|
|
598
|
|
|
|
598
|
|
|
|
|
|
|
|
|
|
|
Total fixed rate debentures
|
|
|
2,802
|
|
|
|
2,801
|
|
Fixed rate notes, payable principally to insurance companies,
weighted average rate 9.1%, due through 2014
|
|
|
126
|
|
|
|
145
|
|
Project lease financing, weighted average rate 5.1%, due through
2014
|
|
|
140
|
|
|
|
148
|
|
Pollution control revenue bonds, weighted average rate 5.9%, due
through 2034
|
|
|
53
|
|
|
|
53
|
|
Other loans, weighted average rate 7.7%, due through 2019
|
|
|
39
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,980
|
|
|
|
3,772
|
|
Less: amount included in current maturities
|
|
|
62
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,918
|
|
|
$
|
3,745
|
|
|
|
|
|
|
|
|
|
|
The aggregate long-term debt maturing during the next five years
is as follows (in millions): 2008 $62 (included in
current liabilities); 2009 $143; 2010
$29; 2011 $698 and 2012 $845.
56
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2007, the Corporations fixed rate
debentures have a principal amount of $2,816 million
($2,802 million net of unamortized discount). Interest
rates on the outstanding fixed rate debentures have a weighted
average rate of 7.3%.
The Corporation has a $3.0 billion syndicated revolving
credit facility (the facility), which can be used for borrowings
and letters of credit, substantially all of which is committed
through May 2012. At December 31, 2007, the Corporation has
available capacity on the facility of $2,780 million.
Current borrowings under the facility bear interest at 0.525%
above the London Interbank Offered Rate and a facility fee of
0.125% per annum is payable on the amount of the credit line.
The interest rate and facility fee are subject to adjustment if
the Corporations credit rating changes.
The Corporation has a
364-day
asset-backed credit facility securitized by certain accounts
receivable from its marketing operations, which are sold to a
wholly-owned subsidiary. This asset-backed funding arrangement
allows the Corporation to borrow up to $800 million subject
to sufficient levels of eligible receivables. The credit line
matures in October 2008. Borrowings under the asset-backed
credit facility represent floating rate debt for which the
weighted average interest rate was 5.6% for 2007. At
December 31, 2007, total collateralized accounts receivable
of $1,336 million are serviced by the Corporation and
recorded on its balance sheet but are not available to pay the
general obligations of the Corporation before repayment of
outstanding borrowings under the asset-backed facility.
At December 31, 2007, the Corporation classified an
aggregate of $600 million of borrowings under short-term
credit facilities as long term debt, based on the available
capacity under the $3.0 billion syndicated revolving credit
facility. These borrowings consist of $300 million under a
short-term committed facility, $250 million under the
asset-backed credit facility and $50 million under
uncommitted lines at December 31, 2007.
The Corporations long-term debt agreements contain a
financial covenant that restricts the amount of total borrowings
and secured debt. At December 31, 2007, the Corporation is
permitted to borrow up to an additional $12.3 billion for
the construction or acquisition of assets. The Corporation has
the ability to borrow up to an additional $2.6 billion of
secured debt at December 31, 2007.
The total amount of interest paid (net of amounts capitalized),
principally on short-term and long-term debt, was
$257 million, $200 million and $245 million in
2007, 2006 and 2005, respectively. The Corporation capitalized
interest of $50 million, $100 million and
$80 million in 2007, 2006 and 2005, respectively. In 2005,
the Corporation recorded charges of $39 million
($26 million after income taxes) for premiums on bond
repurchases, which are reflected in other income in the income
statement.
57
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
8.
|
Share-Based
Compensation
|
The Corporation awards restricted common stock and stock options
under its Amended and Restated 1995 Long-Term Incentive Plan.
Generally, stock options vest in one to three years from the
date of grant, have a
10-year
option life, and the exercise price equals or exceeds the market
price on the date of grant. Outstanding restricted common stock
generally vests in three years from the date of grant.
Share-based compensation expense consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Taxes
|
|
|
After Taxes
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Millions of dollars)
|
|
|
Stock options
|
|
$
|
36
|
|
|
$
|
30
|
|
|
$
|
23
|
|
|
$
|
19
|
|
Restricted stock
|
|
|
51
|
|
|
|
38
|
|
|
|
31
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
87
|
|
|
$
|
68
|
|
|
$
|
54
|
|
|
$
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pre-tax compensation expense for restricted common stock
was $28 million in 2005. The following pro forma financial
information for the year ended December 31, 2005 presents
the effect on net income and earnings per share as if the
Corporation commenced expensing of stock options on
January 1, 2005 instead of on January 1, 2006
(millions of dollars, except per share data).
|
|
|
|
|
Net income
|
|
$
|
1,226
|
|
Add: stock-based employee compensation expense included in net
income, net of taxes
|
|
|
18
|
|
Less: total stock-based employee compensation expense determined
using the fair value method, net of taxes
|
|
|
(37
|
)
|
|
|
|
|
|
Pro forma net income
|
|
$
|
1,207
|
|
|
|
|
|
|
Net income per share as reported
|
|
|
|
|
Basic
|
|
$
|
4.32
|
|
Diluted
|
|
|
3.93
|
|
Pro forma net income per share
|
|
|
|
|
Basic
|
|
$
|
4.25
|
|
Diluted
|
|
|
3.87
|
|
Based on restricted stock and stock option awards outstanding at
December 31, 2007, unearned compensation expense, before
income taxes, will be recognized in future years as follows (in
millions): 2008 $68, 2009 $39 and
2010 $5.
58
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Corporations stock option and restricted stock
activity consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options
|
|
|
Restricted Stock
|
|
|
|
|
|
|
Weighted-
|
|
|
Shares of
|
|
|
Weighted-
|
|
|
|
|
|
|
Average
|
|
|
Restricted
|
|
|
Average
|
|
|
|
|
|
|
Exercise Price
|
|
|
Common
|
|
|
Price on Date
|
|
|
|
Options
|
|
|
per Share
|
|
|
Stock
|
|
|
of Grant
|
|
|
|
(Thousands)
|
|
|
|
|
|
(Thousands)
|
|
|
|
|
|
Outstanding at January 1, 2005
|
|
|
11,361
|
|
|
$
|
21.00
|
|
|
|
4,404
|
|
|
$
|
19.52
|
|
Granted
|
|
|
3,282
|
|
|
|
30.91
|
|
|
|
1,121
|
|
|
|
30.79
|
|
Exercised
|
|
|
(3,099
|
)
|
|
|
19.96
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
|
|
|
|
|
|
|
|
(989
|
)
|
|
|
19.89
|
|
Forfeited
|
|
|
(93
|
)
|
|
|
24.85
|
|
|
|
(173
|
)
|
|
|
19.67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2005
|
|
|
11,451
|
|
|
|
24.09
|
|
|
|
4,363
|
|
|
|
22.32
|
|
Granted
|
|
|
2,853
|
|
|
|
49.46
|
|
|
|
984
|
|
|
|
50.40
|
|
Exercised
|
|
|
(1,283
|
)
|
|
|
22.96
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
|
|
|
|
|
|
|
|
(237
|
)
|
|
|
22.78
|
|
Forfeited
|
|
|
(98
|
)
|
|
|
40.07
|
|
|
|
(66
|
)
|
|
|
30.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
12,923
|
|
|
|
29.68
|
|
|
|
5,044
|
|
|
|
27.68
|
|
Granted
|
|
|
3,066
|
|
|
|
53.82
|
|
|
|
1,032
|
|
|
|
53.92
|
|
Exercised
|
|
|
(4,566
|
)
|
|
|
24.07
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
|
|
|
|
|
|
|
|
(1,184
|
)
|
|
|
24.53
|
|
Forfeited
|
|
|
(131
|
)
|
|
|
46.41
|
|
|
|
(91
|
)
|
|
|
36.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
11,292
|
|
|
|
38.31
|
|
|
|
4,801
|
|
|
|
33.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2005
|
|
|
8,181
|
|
|
$
|
21.36
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2006
|
|
|
6,832
|
|
|
|
22.08
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2007
|
|
|
5,408
|
|
|
|
27.34
|
|
|
|
|
|
|
|
|
|
The table below summarizes information regarding the outstanding
and exercisable stock options as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Options
|
|
|
Exercisable Options
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted-
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Average
|
|
Range of
|
|
|
|
|
Contractual
|
|
|
Exercise Price
|
|
|
|
|
|
Exercise Price
|
|
Exercise Prices
|
|
Options
|
|
|
Life
|
|
|
per Share
|