HESS CORP
10-Ks and 10-Qs
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Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
|
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, 2009 |
|
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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 | |
|
(State or other jurisdiction
of
incorporation or organization) |
(I.R.S. Employer
Identification Number) |
|
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1185 AVENUE OF THE AMERICAS,
NEW YORK, N.Y. (Address of principal executive offices) |
10036
(Zip Code) |
(Registrant’s telephone number, including area code, is
(212) 997-8500)
Securities registered pursuant to Section 12(b) of the
Act:
|
Title of Each Class
|
Name of Each Exchange on Which Registered
|
|
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Common Stock (par value $1.00)
|
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. 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 whether the registrant submitted
electronically and posted on its Corporate website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes
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 Registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
þ
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):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
(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 $17,579,000,000
computed using the outstanding common shares and closing market
price on June 30, 2009.
At December 31, 2009, there were 327,229,488 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 5, 2010.
HESS
CORPORATION
Form 10-K
TABLE OF
CONTENTS
1
Table of Contents
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, Colombia,
Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia,
Libya, Malaysia, Norway, Peru, Russia, Thailand, the United
Kingdom and the United States. The M&R segment manufactures
refined petroleum products and purchases, markets and trades,
refined petroleum products, natural gas and electricity. The
Corporation owns 50% of 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.
Exploration
and Production
The Corporation’s total proved developed and undeveloped
reserves at December 31 were as follows:
|
Crude Oil
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Total Barrels of
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|||||||||||||||||||||||
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and
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Oil
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|||||||||||||||||||||||
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Natural Gas
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Equivalent
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|||||||||||||||||||||||
| Liquids | Natural Gas | (BOE)* | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
| (Millions of barrels) | (Millions of mcf) | (Millions of barrels) | ||||||||||||||||||||||
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Developed
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||||||||||||||||||||||||
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United States
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154 | 119 | 205 | 202 | 188 | 153 | ||||||||||||||||||
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Europe
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171 | 192 | 417 | 502 | 241 | 276 | ||||||||||||||||||
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Africa
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241 | 237 | 59 | 60 | 251 | 247 | ||||||||||||||||||
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Asia and other
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27 | 23 | 864 | 667 | 170 | 134 | ||||||||||||||||||
| 593 | 571 | 1,545 | 1,431 | 850 | 810 | |||||||||||||||||||
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Undeveloped
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||||||||||||||||||||||||
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United States
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95 | 108 | 101 | 74 | 112 | 120 | ||||||||||||||||||
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Europe
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159 | 140 | 225 | 137 | 197 | 162 | ||||||||||||||||||
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Africa
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73 | 87 | 12 | 9 | 75 | 89 | ||||||||||||||||||
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Asia and other
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47 | 64 | 938 | 1,122 | 203 | 251 | ||||||||||||||||||
| 374 | 399 | 1,276 | 1,342 | 587 | 622 | |||||||||||||||||||
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Total
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||||||||||||||||||||||||
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United States
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249 | 227 | 306 | 276 | 300 | 273 | ||||||||||||||||||
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Europe
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330 | 332 | 642 | 639 | 438 | 438 | ||||||||||||||||||
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Africa
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314 | 324 | 71 | 69 | 326 | 336 | ||||||||||||||||||
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Asia and other
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74 | 87 | 1,802 | 1,789 | 373 | 385 | ||||||||||||||||||
| 967 | 970 | 2,821 | 2,773 | 1,437 | 1,432 | |||||||||||||||||||
| * | 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, 41% of the
Corporation’s worldwide proved reserves are undeveloped at
December 31, 2009 (43% at December 31, 2008). Proved
reserves held under production sharing contracts at
December 31, 2009 totaled 24% of crude oil and natural gas
liquids and 57% of natural gas reserves (28% and 58%
respectively, at December 31, 2008).
The Securities and Exchange Commission (SEC) revised its oil and
gas reserve estimation and disclosure standards effective
December 31, 2009. See the Supplementary Oil and Gas Data
on pages 77 through 84 in the accompanying financial statements
for additional information on the Corporation’s oil and gas
reserves.
2
Table of Contents
Worldwide crude oil, natural gas liquids and natural gas
production was as follows:
| 2009 | 2008 | 2007 | ||||||||||
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Crude oil (thousands of barrels per day)
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||||||||||||
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United States
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||||||||||||
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Onshore
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21 | 17 | 15 | |||||||||
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Offshore
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39 | 15 | 16 | |||||||||
| 60 | 32 | 31 | ||||||||||
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Europe
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United Kingdom
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21 | 29 | 38 | |||||||||
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Norway
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13 | 16 | 19 | |||||||||
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Denmark
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12 | 11 | 12 | |||||||||
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Russia
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37 | 27 | 24 | |||||||||
| 83 | 83 | 93 | ||||||||||
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Africa
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Equatorial Guinea
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70 | 72 | 56 | |||||||||
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Algeria
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14 | 15 | 22 | |||||||||
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Gabon
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14 | 14 | 14 | |||||||||
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Libya
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22 | 23 | 23 | |||||||||
| 120 | 124 | 115 | ||||||||||
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Asia and other
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Azerbaijan
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8 | 7 | 16 | |||||||||
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Other
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8 | 6 | 5 | |||||||||
| 16 | 13 | 21 | ||||||||||
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Total
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279 | 252 | 260 | |||||||||
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Natural gas liquids (thousands of barrels per day)
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United States
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||||||||||||
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Onshore
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7 | 7 | 7 | |||||||||
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Offshore
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4 | 3 | 3 | |||||||||
| 11 | 10 | 10 | ||||||||||
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Europe
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||||||||||||
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United Kingdom
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2 | 3 | 4 | |||||||||
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Norway
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1 | 1 | 1 | |||||||||
| 3 | 4 | 5 | ||||||||||
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Total
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14 | 14 | 15 | |||||||||
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Natural gas (thousands of mcf per day)
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||||||||||||
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United States
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||||||||||||
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Onshore
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38 | 41 | 42 | |||||||||
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Offshore
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55 | 37 | 46 | |||||||||
| 93 | 78 | 88 | ||||||||||
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Europe
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||||||||||||
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United Kingdom
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118 | 223 | 231 | |||||||||
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Norway
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21 | 22 | 18 | |||||||||
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Denmark
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12 | 10 | 10 | |||||||||
| 151 | 255 | 259 | ||||||||||
3
Table of Contents
| 2009 | 2008 | 2007 | ||||||||||
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Asia and other
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||||||||||||
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Joint Development Area of Malaysia/Thailand (JDA)
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294 | 185 | 115 | |||||||||
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Thailand
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85 | 87 | 90 | |||||||||
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Indonesia
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65 | 82 | 59 | |||||||||
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Other
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2 | 2 | 2 | |||||||||
| 446 | 356 | 266 | ||||||||||
|
Total
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690 | 689 | 613 | |||||||||
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Barrels of oil equivalent*
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408 | 381 | 377 | |||||||||
| * | Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). |
A description of our significant E&P operations follows:
United
States
At December 31, 2009, 21% of the Corporation’s total
proved reserves were located in the United States. During 2009,
24% of the Corporation’s crude oil and natural gas liquids
production and 13% of its natural gas production were from
United States operations. The Corporation’s production in
the United States was principally from properties offshore in
the Gulf of Mexico, which include the Shenzi (Hess 28%), Llano
(Hess 50%), Conger (Hess 38%), Baldpate (Hess 50%), Hack Wilson
(Hess 25%) and Penn State (Hess 50%) fields, as well as onshore
properties in the Williston Basin of North Dakota and in the
Permian Basin of Texas.
In the deepwater Gulf of Mexico, production commenced at the
Shenzi Field in March 2009. Net production from Shenzi averaged
approximately 25,000 barrels of oil equivalent per day
(boepd) in 2009. The operator plans on drilling additional
production wells at Shenzi in 2010.
In North Dakota, the Corporation holds a net acreage position in
the Bakken shale play of approximately 510,000 acres. In
2009, the Corporation sanctioned a development program for the
Bakken. The Corporation plans to expand production facilities
and increase the rig count to 10 from 3 over the next
18 months, and invest about $1 billion per year over
the next five years. As a result, the Corporation projects an
increase in net production from approximately 10,000 boepd in
2009 to approximately 80,000 boepd in 2015.
The Corporation is developing a residual oil zone at the
Seminole-San Andres Unit (Hess 34%) in Texas where carbon
dioxide gas supplied from its interests in the West Bravo Dome
and Bravo Dome fields in New Mexico is being injected to enhance
recovery of crude oil.
At the Pony prospect on Green Canyon Block 468 (Hess 100%)
in the deepwater Gulf of Mexico, engineering and design work for
field development progressed during 2009. The Corporation plans
to drill an appraisal well on Green Canyon Block 469 in
2010.
In 2009 the Corporation acquired rights to explore a total of
more than 80,000 net acres in the Marcellus gas shale
formation in Pennsylvania. The Corporation is operator and holds
a 100% interest on approximately 50,000 acres and holds a
50% non-operated interest in the remaining acreage. Exploration
drilling activity is expected to commence in 2010.
At December 31, 2009, the Corporation had interests in 331
total blocks in the Gulf of Mexico, of which 292 were
exploration blocks comprising 1.1 million net undeveloped
acres and the remainder were held for production and development
operations.
Europe
At December 31, 2009, 30% of the Corporation’s total
proved reserves were located in Europe (United Kingdom 8%,
Norway 13%, Denmark 3% and Russia 6%). During 2009, 29% of the
Corporation’s crude oil and natural gas liquids production
and 22% of its natural gas production were from European
operations.
4
Table of Contents
United Kingdom:
Production of crude oil
and natural gas liquids from the United Kingdom North Sea was
principally from the Corporation’s non-operated interests
in the Nevis (Hess 39%), Schiehallion (Hess 16%), Clair (Hess
9%), Bittern (Hess 28%) and Beryl (Hess 22%) fields. Natural gas
production from the United Kingdom was primarily from the
Easington Catchment Area (Hess 32%), Bacton area (Hess 22%),
Beryl (Hess 22%), Everest (Hess 19%), Lomond (Hess 17%), Nevis
(Hess 39%), Atlantic (Hess 25%) and Cromarty (Hess 90%) fields.
The operator plans to drill additional production wells at Beryl
in 2010.
Norway:
Substantially all of the 2009
and 2008 Norwegian production was from the Corporation’s
interest in the Valhall Field (Hess 28%). A field redevelopment
for Valhall commenced in 2007 and is expected to be completed in
2011. In 2010, the operator plans on drilling additional
production and injection wells at Valhall. Additionally in 2010,
the operator will continue to work on the Valhall Flank Gas Lift
project, which was sanctioned in 2009 and is expected to be
completed in 2011. The Corporation also holds an interest in the
Snohvit (Hess 3%), Snorre (Hess 1%) and Hod (Hess 25%) fields.
All four of the Corporation’s Norwegian field interests are
located offshore.
In December 2009, the Corporation agreed to a strategic exchange
of all of its interests in Gabon and the Clair Field in the
United Kingdom for an additional 28% interest in Valhall and 25%
interest in Hod. The transaction, which has an effective date of
January 1, 2010, is subject to various regulatory and other
approvals. In addition, the partners are in discussions
regarding the applicability of pre-emption to this transaction.
Denmark:
Crude oil and natural gas
production comes from the Corporation’s interest in the
South Arne Field (Hess 58%). In 2010, the Corporation plans a
two well production drilling program.
Russia:
The Corporation’s
activities in the Russian Federation are conducted through its
80% interest in a subsidiary operating in the Volga-Urals region
of Russia. As of December 31, 2009, this subsidiary had
exploration and production rights in 13 license areas in the
Samara Oblast. In December 2009 this subsidiary also secured
rights in the Novomaliklinsky license area, which lies in the
Ulyanovsk Oblast. Production currently comes from ten license
areas, but exploration and development investment is planned in
all 14 license areas.
Africa
At December 31, 2009, 23% of the Corporation’s total
proved reserves were located in Africa (Equatorial Guinea 8%,
Algeria 2%, Libya 11% and Gabon 2%). During 2009, 41% of the
Corporation’s 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. The Corporation
plans to drill additional production wells at Okume in 2010.
Algeria:
The Corporation has a 49%
interest in a venture with the Algerian national oil company,
that redeveloped 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%). The
Corporation also owns a 100% interest in offshore exploration
Area 54 in the Mediterranean Sea, where a successful exploration
well was drilled in 2008. In 2009, the Corporation successfully
flow tested the first exploration well and subsequently drilled
and successfully flow tested a down-dip appraisal well. In 2010,
the Corporation plans to reprocess 3D seismic, integrating
acquired well information, and will continue technical and
commercial evaluation of the block.
Gabon:
The Corporation’s
activities in Gabon are conducted through its wholly-owned
Gabonese subsidiary, where the Corporation has interests in the
Rabi Kounga, Toucan and Atora fields. In the fourth quarter of
2009, the Corporation agreed to a strategic exchange of all of
its interests in Gabon for additional interests in the Valhall
and Hod fields offshore Norway.
Egypt:
The Corporation has an interest
in the West Mediterranean Block 1 concession (West Med
Block) (Hess 55%), which contains natural gas discoveries and
additional exploration opportunities. The Corporation is
currently evaluating technical and commercial options for this
block and further exploratory drilling is planned. The
Corporation also owns a 100% interest in Block 1 offshore
Egypt in the Red Sea. During 2009 the Corporation acquired and
completed the reprocessing of seismic data for this block.
5
Table of Contents
Ghana:
The Corporation holds a 100%
interest in the Deepwater Tano Cape Three Points License. The
Corporation is evaluating 3D seismic in anticipation of drilling
the second exploration well on this prospect in late 2010 or
early 2011.
Asia and
Other
At December 31, 2009, 26% of the Corporation’s total
proved reserves were located in the Asia and other region (JDA
11%, Indonesia 9%, Thailand 3%, Azerbaijan 2% and Malaysia 1%).
During 2009, 6% of the Corporation’s crude oil and natural
gas liquids production and 65% of its natural gas production
were from Asia and other operations.
Joint Development Area of Malaysia/Thailand
(JDA):
The Corporation owns an interest in
Block
A-18
of the JDA (Hess 50%) in the Gulf of Thailand. Phase 2 gas sales
commenced in November of 2008. In 2009, the Corporation acquired
a 50% interest in Blocks PM301 and PM302 in Malaysia, which are
adjacent to Block
A-18
of the
JDA.
Indonesia:
The Corporation’s
natural gas production in Indonesia primarily comes from its
interests offshore in the Ujung Pangkah project (Hess 75%),
which commenced production in 2007, and the Natuna A Field (Hess
23%). Additional production from a Phase 2 oil project at Ujung
Pangkah commenced in 2009. The Corporation also owned an
interest in the onshore Jambi Merang natural gas development
project (Hess 25%), which was sold in January 2010. In May 2009,
the Corporation obtained a 100% working interest in the offshore
South Sesulu Block, where the Corporation is planning to acquire
and process seismic in 2010. The Corporation also holds a 100%
working interest in the offshore Semai V Block, where the
Corporation is evaluating seismic and plans to drill an
exploration well in late 2010 or early 2011.
Thailand:
The Corporation’s
natural gas production in Thailand primarily comes from the
offshore Pailin Field (Hess 15%) and the onshore Sinphuhorm
Block (Hess 35%).
Azerbaijan:
The Corporation has an
interest in the Azeri-Chriag-Gunashli (ACG) fields (Hess 3%) in
the Caspian Sea. In 2010, production drilling will continue and
the operator will seek sanction to install an additional
production and drilling platform, which will include processing
facilities and related infrastructure.
Australia:
The Corporation holds a 100%
interest in an exploration license covering 780,000 acres
in the Carnarvon basin offshore Western Australia (WA-390-P
Block). Through December 31, 2009, the Corporation has
drilled 11 of the 16 commitment wells on the block, nine of
which were natural gas discoveries. The Corporation plans to
drill the remaining five commitment wells on the block in 2010.
The Corporation also holds a 50% interest in WA-404-P Block
located offshore Western Australia, which covers a total area of
680,000 acres. The operator completed a successful
exploration well on this block in 2009 and plans to drill the
remaining eight commitment wells on this block in 2010. In
January 2010, the operator announced that the first well of the
2010 program discovered natural gas.
Brazil:
The Corporation has interests
in two blocks located offshore Brazil, BM-S-22 (Hess 40%) and
BM-ES-30 (Hess 30%). In 2009, two exploration wells were
completed on BM-S-22. A notice of discovery was filed for the
first well and the second well was expensed. In 2010, the
operator of BM-S-22 plans to commence drilling of a third
exploration well in the second half of the year. In 2009, the
Corporation also drilled an exploration well on BM-ES-30, which
was expensed.
Peru:
The Corporation has an interest
in Block 64 in Peru (Hess 50%). At the end of 2009, the
Corporation was drilling a sidetrack to an exploration well on
this block. Further evaluation work is planned for 2010.
Colombia:
The Corporation has interests
in offshore Blocks RC 6 and RC 7 (Hess 30%). During 2009 the
Corporation acquired 3D seismic for those blocks. Additional 3D
seismic will be acquired and processed in 2010.
Oil and
Gas Reserves
The Corporation’s net proved oil and gas reserves at the
end of 2009, 2008 and 2007 are presented under the Supplementary
Oil and Gas Data on pages 77 through 84 in the accompanying
financial statements.
During 2009, the Corporation provided oil and gas reserve
estimates for 2008 to the United States Department of Energy.
Such estimates are consistent with the information furnished to
the SEC on
Form 10-K
for the year ended
6
Table of Contents
December 31, 2008, 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 by
the M&R segment on a spot basis and under contracts for
varying periods of time to local distribution companies, and
commercial, industrial and other purchasers. The
Corporation’s United States natural gas production is
expected to approximate 30% of its 2010 sales commitments under
long-term contracts. The Corporation attempts to minimize supply
risks associated with its United States natural gas supply
commitments by entering into purchase contracts with third
parties having reliable sources of supply and by leasing storage
facilities.
Outside of the United States and the United Kingdom, the
Corporation generally sells its natural gas production under
long-term sales contracts at prices that are periodically
adjusted due to changes in commodity prices or other indices.
Average
selling prices and average production costs
| 2009 | 2008 | 2007 | ||||||||||
|
Average selling prices*
|
||||||||||||
|
Crude oil (per barrel)
|
||||||||||||
|
United States
|
$ | 60.67 | $ | 96.82 | $ | 69.23 | ||||||
|
Europe
|
47.02 | 78.75 | 60.99 | |||||||||
|
Africa
|
48.91 | 78.72 | 62.04 | |||||||||
|
Asia and other
|
63.01 | 97.07 | 72.17 | |||||||||
|
Worldwide
|
51.62 | 82.04 | 63.44 | |||||||||
|
Natural gas liquids (per barrel)
|
||||||||||||
|
United States
|
$ | 36.57 | $ | 64.98 | $ | 51.89 | ||||||
|
Europe
|
43.23 | 74.63 | 57.20 | |||||||||
|
Worldwide
|
38.47 | 67.61 | 53.72 | |||||||||
|
Natural gas (per mcf)
|
||||||||||||
|
United States
|
$ | 3.36 | $ | 8.61 | $ | 6.67 | ||||||
|
Europe
|
5.15 | 9.44 | 6.13 | |||||||||
|
Asia and other
|
5.06 | 5.24 | 4.71 | |||||||||
|
Worldwide
|
4.85 | 7.17 | 5.60 | |||||||||
|
Average production (lifting) costs per barrel of oil equivalent
produced**
|
||||||||||||
|
United States
|
$ | 13.72 | $ | 18.46 | $ | 13.56 | ||||||
|
Europe
|
15.77 | 17.12 | 14.06 | |||||||||
|
Africa
|
10.93 | 10.22 | 9.09 | |||||||||
|
Asia and other
|
7.65 | 8.48 | 8.41 | |||||||||
|
Worldwide
|
12.12 | 13.43 | 11.50 | |||||||||
| * | Includes inter-company transfers valued at approximate market prices and the effect of the Corporation’s hedging activities. | |
| ** | Production (lifting) costs consist of amounts incurred to operate and maintain the Corporation’s producing oil and gas wells, related equipment and facilities, transportation costs and production and severance taxes. 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.
7
Table of Contents
Gross and
net undeveloped acreage at December 31, 2009
|
Undeveloped
|
||||||||
| Acreage* | ||||||||
| Gross | Net | |||||||
| (In thousands) | ||||||||
|
United States
|
2,993 | 1,969 | ||||||
|
Europe
|
2,274 | 760 | ||||||
|
Africa
|
9,937 | 6,440 | ||||||
|
Asia and other
|
9,546 | 5,099 | ||||||
|
Total**
|
24,750 | 14,268 | ||||||
| * | Includes acreage held under production sharing contracts. | |
| ** | Licenses covering approximately 30% of the Corporation’s net undeveloped acreage held at December 31, 2009 are scheduled to expire during the next three years pending the results of exploration activities. These scheduled expirations are largely in Africa and the United States. |
Gross and
net developed acreage and productive wells at December 31,
2009
|
Developed
|
||||||||||||||||||||||||
|
Acreage
|
||||||||||||||||||||||||
|
Applicable to
|
Productive Wells* | |||||||||||||||||||||||
| Productive Wells | Oil | Gas | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
United States
|
542 | 466 | 901 | 487 | 60 | 45 | ||||||||||||||||||
|
Europe
|
1,379 | 771 | 287 | 122 | 150 | 31 | ||||||||||||||||||
|
Africa
|
9,938 | 970 | 1,021 | 164 | — | — | ||||||||||||||||||
|
Asia and other
|
2,190 | 625 | 69 | 7 | 349 | 78 | ||||||||||||||||||
|
Total
|
14,049 | 2,832 | 2,278 | 780 | 559 | 154 | ||||||||||||||||||
| * | Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 20 gross wells and 15 net wells. |
Number of
net exploratory and development wells drilled
|
Net Exploratory
|
Net Development
|
|||||||||||||||||||||||
| Wells | Wells | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
|
Productive wells
|
||||||||||||||||||||||||
|
United States
|
— | 2 | 1 | 44 | 50 | 54 | ||||||||||||||||||
|
Europe
|
7 | 11 | 3 | 12 | 11 | 14 | ||||||||||||||||||
|
Africa
|
1 | 1 | 1 | 23 | 23 | 23 | ||||||||||||||||||
|
Asia and other
|
8 | 5 | 3 | 12 | 25 | 15 | ||||||||||||||||||
| 16 | 19 | 8 | 91 | 109 | 106 | |||||||||||||||||||
|
Dry holes
|
||||||||||||||||||||||||
|
United States
|
4 | — | 1 | — | 1 | — | ||||||||||||||||||
|
Europe
|
— | 3 | 1 | — | — | — | ||||||||||||||||||
|
Africa
|
— | 2 | 1 | — | — | — | ||||||||||||||||||
|
Asia and other
|
2 | 1 | — | — | — | — | ||||||||||||||||||
| 6 | 6 | 3 | — | 1 | — | |||||||||||||||||||
|
Total
|
22 | 25 | 11 | 91 | 110 | 106 | ||||||||||||||||||
8
Table of Contents
Number of wells in process of drilling at December 31,
2009:
|
Gross
|
Net
|
|||||||
| Wells | Wells | |||||||
|
United States
|
11 | 4 | ||||||
|
Europe
|
2 | 1 | ||||||
|
Africa
|
9 | 1 | ||||||
|
Asia and other
|
8 | 2 | ||||||
|
Total
|
30 | 8 | ||||||
Number of net waterfloods and
pressure maintenance projects in process of installation at
December 31, 2009 — 1
Marketing
and Refining
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 (FCC)
and a delayed coker unit.
The following table summarizes capacity and utilization rates
for HOVENSA:
|
Refinery
|
Refinery Utilization | |||||||||||||||
| Capacity | 2009 | 2008 | 2007 | |||||||||||||
|
(Thousands of
|
||||||||||||||||
| barrels per day) | ||||||||||||||||
|
Crude
|
500 | 80.3% | 88.2% | 90.8% | ||||||||||||
|
Fluid catalytic cracker
|
150 | 70.2% | 72.7% | 87.1% | ||||||||||||
|
Coker
|
58 | 81.6% | 92.4% | 83.4% | ||||||||||||
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 HOVENSA’s
remaining production at market prices.
Gross crude runs at HOVENSA averaged 402,000 barrels per
day in 2009 compared with 441,000 barrels per day in 2008
and 454,000 barrels per day in 2007. The 2009 and 2008
utilization rates for HOVENSA reflect weaker refining margins
and planned and unplanned maintenance. The 2008 utilization
rates also reflect a refinery wide shut down for Hurricane Omar.
In January 2010, HOVENSA commenced a turnaround of its FCC unit
which is expected to take approximately 40 days.
Port Reading Facility:
The Corporation
owns and operates a fluid catalytic cracking facility in Port
Reading, New Jersey, with a capacity of 70,000 barrels per
day. This facility, which processes residual fuel oil and vacuum
gas oil, operated at a rate of approximately 63,000 barrels
per day in 2009 compared with 64,000 barrels per day in
2008 and 61,000 barrels per day in 2007. Substantially all
of Port Reading’s production is gasoline and heating oil.
The Corporation is planning a turnaround for the Port Reading
refining facility in the second quarter of 2010, which is
expected to take approximately 35 days.
9
Table of Contents
Marketing
The Corporation markets refined petroleum products, natural gas
and electricity 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.
The Corporation had 1,357
HESS
®
gasoline stations at December 31, 2009, including stations
owned by its WilcoHess joint venture (Hess 44%). Approximately
92% of the gasoline stations are operated by the Corporation or
WilcoHess. Of the operated stations, 94% have convenience stores
on the sites. Most of the Corporation’s gasoline stations
are in New York, New Jersey, Pennsylvania, Florida,
Massachusetts, North Carolina and South Carolina.
The table below summarizes marketing sales volumes:
| 2009* | 2008* | 2007* | ||||||||||
|
Refined Product sales (thousands of barrels per day)
|
||||||||||||
|
Gasoline
|
236 | 234 | 210 | |||||||||
|
Distillates
|
134 | 143 | 147 | |||||||||
|
Residuals
|
67 | 56 | 62 | |||||||||
|
Other
|
36 | 39 | 32 | |||||||||
|
Total refined product sales
|
473 | 472 | 451 | |||||||||
|
Natural gas (thousands of mcf per day)
|
2,010 | 1,955 | 1,890 | |||||||||
|
Electricity (megawatts round the clock)
|
4,306 | 3,152 | 2,821 | |||||||||
| * | Of total refined products sold in 2009 approximately 45% was obtained from HOVENSA and Port Reading and in 2008 and 2007 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. |
The Corporation owns 20 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 9 million barrels, which is operated
for third party storage.
The Corporation has a 50% interest in Bayonne Energy Center,
LLC, a joint venture that plans to build a natural gas fired
electric generating station on property owned by Hess in
Bayonne, New Jersey. The joint venture will sell electricity
into the New York City market by a direct connection with the
Con Edison Gowanus substation. Construction of the facility is
scheduled to begin in mid-2010 and operations are to commence in
late 2011.
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.
Majority-owned subsidiaries of the Corporation are pursuing
investments in liquified natural gas regasification terminals
and related supply, trading and marketing opportunities.
Necessary regulatory approvals are being pursued for terminal
projects on owned properties located in Fall River,
Massachusetts, and Shannon, Ireland. In 2009 the Corporation
leased property, with an option to purchase, in Logan Township,
New Jersey for potential regasification facilities. In addition,
a subsidiary of the Corporation is exploring the development of
fuel cell technology.
For additional financial information by segment see Note 16,
Segment Information in the notes to the financial statements.
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 Corporation’s financial condition or
10
Table of Contents
results of operations. The Corporation anticipates capital
expenditures for facilities, primarily to comply with federal,
state and local environmental standards, of approximately
$50 million in 2010. For further discussion of
environmental matters see the Environment, Health and Safety
section of Item 7.
Management’s Discussion and
Analysis of Financial Condition and Results of Operations.
The number of persons employed by the Corporation at year end
was approximately 13,300 in 2009 and 13,500 in 2008.
The Corporation’s 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 Corporation’s Code of
Business Conduct and Ethics, its Corporate 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 Corporation’s 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 Corporation’s chief executive officer is unaware of any
violation of the NYSE’s 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 and
most recently have been affected by changes in demand associated
with the global economic downturn. 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. To the extent that
we engage in hedging activities to mitigate commodity price
volatility, we may not realize the benefit of price increases
above the hedged price. Changes in commodity prices can also
have a material impact on collateral and margin requirements
under our derivative contracts. In addition, we utilize
significant bank credit facilities to support these collateral
and margin requirements. An inability to renew or replace such
credit facilities as they mature would negatively impact our
liquidity.
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 unexpected adverse 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 increased in recent years which could negatively affect
expected economic returns. Reserve replacement can also be
achieved through acquisition. Although due diligence is used in
evaluating acquired oil and gas properties, similar risks may be
encountered in the production of oil and gas on properties
acquired from others.
11
Table of Contents
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, 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 or
nationalization of property, mandatory government participation,
cancellation or amendment of contract rights, and changes in
import regulations, limitations on access to exploration and
development opportunities, as well as other political
developments may affect our operations. Some of the
international areas in which we operate and the partners with
whom we operate, are politically less stable than other areas
and partners. The threat of terrorism around the world also
poses additional risks to the operations of the oil and gas
industry. We market motor fuels through lessee-dealers and
wholesalers in 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 various other states.
Environmental Risk:
Our oil and gas
operations, like those of the industry, are subject to
environmental risk 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 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.
Climate Change Risk:
We recognize that climate
change is a global environmental concern. Continuing political
and social attention to the issue of climate change has resulted
in both existing and pending international agreements and
national, regional or local legislation and regulatory measures
to limit greenhouse gas emissions. These agreements and measures
may require significant equipment modifications, operational
changes, taxes, or purchase of emission credits to reduce
emission of greenhouse gases from our operations, as a result of
which we may incur substantial capital expenditures and
compliance, operating, maintenance and remediation costs. In
addition, we manufacture petroleum fuels, which through normal
customer use result in the emission of greenhouse gases.
Regulatory initiatives to reduce the use of these fuels may
reduce our sales of, and revenues from, these products. Finally,
to the extent that climate change may result in more extreme
weather related events, we could experience increased costs
related to prevention, maintenance and remediation of affected
operations in addition to costs and lost revenues related to
delays and shutdowns.
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,
natural gas and electricity. 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, in the recent
past, affected the availability of technical personnel and
drilling rigs and has therefore 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.
12
Table of Contents
| Item 3. | Legal Proceedings |
The Corporation, 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 similar lawsuits, many involving
water utilities or governmental entities, were filed in
jurisdictions across the United States against producers of MTBE
and petroleum refiners who produced gasoline containing MTBE,
including the Corporation. 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. In 2008, the
majority of the cases against the Corporation were settled. In
February 2010, the Corporation reached an agreement in principle
to settle all but three of the remaining cases. The three
unresolved cases consist of two cases that have been
consolidated for pre-trial purposes in the Southern District of
New York as part of a multi-district litigation proceeding and
an action brought in state court by the State of New Hampshire.
In 2007, a pre-tax charge of $40 million was recorded to
cover all of the known MTBE cases against the Corporation.
Over the last several years, many refiners have entered into
consent agreements to resolve the United States Environmental
Protection Agency’s (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 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. The EPA
initially contacted the Corporation and HOVENSA regarding the
Petroleum Refinery Initiative in August 2003. Negotiations with
the EPA and the relevant states and the Virgin Islands are
continuing and substantial progress has been made toward
resolving this matter for both the Corporation and HOVENSA.
While the effect on the Corporation of the Petroleum Refining
Initiative cannot be estimated until a final settlement is
reached and entered by a court, additional significant future
capital expenditures and operating expenses will likely be
incurred by HOVENSA over a number of years. The amount of
penalties, if any, is not expected to be material.
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 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 the EPA has
authority to issue an administrative order assessing penalties
for violation of the Act. HOVENSA has entered into discussions
with the EPA to reach resolution of this matter. The Corporation
does not believe that this matter will result in material
liability to HOVENSA or the Corporation.
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 has entered into
discussions with the appropriate governmental agencies to reach
resolution of this matter and does not believe that it will
result in material liability to HOVENSA or the Corporation.
The Corporation 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 the Corporation, relates to alleged
releases from a petroleum bulk storage terminal in Newark, New
Jersey now owned by the Corporation. The Corporation and over
70 companies entered into an Administrative Order on
Consent with the EPA to study the same contamination. NJDEP has
also sued several other companies linked to a facility
considered by the State to be the largest contributor to river
13
Table of Contents
contamination. In January 2009, these companies added third
party defendants, including the Corporation, to that case. In
June 2007, the 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 the Corporation and others, the 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
Corporation does not believe that this matter will result in
material liability because its terminal could not have
contributed contamination along most of the river’s 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 Corporation, 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 Trustee’s 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.
The Securities and Exchange Commission (SEC) notified the
Corporation 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. In 2009, the SEC advised
that it had completed its investigation and did not intend to
recommend enforcement action against the Corporation.
The Corporation 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, EPA’s
claims or assertions of liability against the Corporation
relating to these sites have not been fully developed. With
respect to the remaining sites, EPA’s 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 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 SEC. In management’s 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.
14
Table of Contents
| Item 4. | Submission of Matters to a Vote of Security Holders |
During the fourth quarter of 2009, 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,
2010 regarding executive officers of the Registrant:
|
Year Individual
|
||||||||||
|
Became an
|
||||||||||
|
Executive
|
||||||||||
|
Name
|
Age | Office Held* | Officer | |||||||
|
John B. Hess
|
55 | Chairman of the Board, Chief Executive Officer and Director | 1983 | |||||||
|
Gregory P. Hill
|
48 | Executive Vice President and President of Worldwide Exploration and Production and Director | 2009 | |||||||
|
F. Borden Walker
|
56 | Executive Vice President and President of Marketing and Refining and Director | 1996 | |||||||
|
Timothy B. Goodell
|
52 | Senior Vice President and General Counsel | 2009 | |||||||
|
Lawrence H. Ornstein
|
58 | Senior Vice President | 1995 | |||||||
|
John P. Rielly
|
47 | Senior Vice President and Chief Financial Officer | 2002 | |||||||
|
John J. Scelfo
|
52 | Senior Vice President | 2004 | |||||||
|
Mykel J. Ziolo
|
57 | Senior Vice President | 2009 | |||||||
|
Sachin J. Mehra
|
39 | Vice President and Treasurer | 2008 | |||||||
| * | 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 opposite his name on May 6, 2009, except for Mr. Ziolo, who was elected effective November 4, 2009. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 5, 2010. |
Except for Messrs. Hill, Goodell, and Mehra, 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. Prior to joining the Corporation,
Mr. Hill served in senior executive positions in
exploration and production operations at Royal Dutch Shell and
its subsidiaries, where he was employed for 25 years.
Before joining the Corporation in 2009, Mr. Goodell was a
partner in the law firm of White & Case LLP.
Mr. Mehra was employed in treasury and financial functions
at General Motors before joining the Corporation in 2007.
| Item 5. | Market for the Registrant’s 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:
| 2009 | 2008 | |||||||||||||||
|
Quarter Ended
|
High | Low | High | Low | ||||||||||||
|
March 31
|
$ | 66.84 | $ | 49.28 | $ | 101.65 | $ | 76.67 | ||||||||
|
June 30
|
69.74 | 49.72 | 137.00 | 88.20 | ||||||||||||
|
September 30
|
57.83 | 46.33 | 129.00 | 71.16 | ||||||||||||
|
December 31
|
62.18 | 51.41 | 82.03 | 35.50 | ||||||||||||
15
Table of Contents
Performance
Graph
Set forth below is a line graph comparing the Corporation’s
cumulative total shareholder return for five years, assuming
reinvestment of dividends on common stock, with the cumulative
total return of:
| • | Standard & Poor’s 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. |
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
Years Ended December 31,
Holders
At December 31, 2009, there were 5,926 stockholders (based
on number of holders of record) who owned a total of
327,229,488 shares of common stock.
Dividends
Cash dividends on common stock totaled $0.40 per share ($0.10
per quarter) during 2009, 2008 and 2007.
Equity
Compensation Plans
Following is information on the Registrant’s equity
compensation plans at December 31, 2009:
|
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
|
12,102,000 | $ | 53.83 | 7,733,000 | * | |||||||
|
Equity compensation plans not approved by security holders**
|
— | — | — | |||||||||
| * | These securities may be awarded as stock options, restricted stock or other awards permitted under the Registrant’s equity compensation plan. | |
| ** | The Corporation has a Stock Award Program pursuant to which each non-employee director receives approximately $150,000 in value of the Corporation’s common stock each year. These awards are made from shares purchased by the Corporation in the open market. |
See Note 8, Share-Based Compensation, in the notes to the
financial statements for further discussion of the
Corporation’s equity compensation plans.
16
Table of Contents
| Item 6. | Selected Financial Data |
A five-year summary of selected financial data follows*:
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
| (Millions of dollars, except per share amounts) | ||||||||||||||||||||
|
Sales and other operating revenues
|
||||||||||||||||||||
|
Crude oil and natural gas liquids
|
$ | 5,665 | $ | 7,764 | $ | 6,303 | $ | 5,307 | $ | 3,219 | ||||||||||
|
Natural gas (including sales of purchased gas)
|
5,894 | 8,800 | 6,877 | 6,826 | 6,423 | |||||||||||||||
|
Refined petroleum products
|
12,931 | 19,765 | 14,741 | 13,339 | 11,317 | |||||||||||||||
|
Electricity
|
3,408 | 3,451 | 2,322 | 1,072 | 373 | |||||||||||||||
|
Convenience store sales and other operating revenues
|
1,716 | 1,354 | 1,484 | 1,632 | 1,499 | |||||||||||||||
|
Total
|
$ | 29,614 | $ | 41,134 | $ | 31,727 | $ | 28,176 | $ | 22,831 | ||||||||||
|
Net income attributable to Hess Corporation
|
$ | 740 | (a) | $ | 2,360 | (b) | $ | 1,832 | (c) | $ | 1,920 | (d) | $ | 1,226 | (e) | |||||
|
Less: preferred stock dividends
|
— | — | — | 44 | 48 | |||||||||||||||
|
Net income applicable to Hess Corporation common shareholders
|
$ | 740 | $ | 2,360 | $ | 1,832 | $ | 1,876 | $ | 1,178 | ||||||||||
|
Earnings per share**
|
||||||||||||||||||||
|
Basic
|
$ | 2.28 | $ | 7.35 | $ | 5.86 | $ | 6.75 | $ | 4.32 | ||||||||||
|
Diluted
|
$ | 2.27 | $ | 7.24 | $ | 5.74 | $ | 6.08 | $ | 3.93 | ||||||||||
|
Total assets
|
$ | 29,465 | $ | 28,589 | $ | 26,131 | $ | 22,442 | $ | 19,158 | ||||||||||
|
Total debt
|
4,467 | 3,955 | 3,980 | 3,772 | 3,785 | |||||||||||||||
|
Total equity
|
13,528 | 12,391 | 10,000 | 8,376 | 6,469 | |||||||||||||||
|
Dividends per share of common stock**
|
$ | .40 | $ | .40 | $ | .40 | $ | .40 | $ | .40 | ||||||||||
| * | Reflects the retrospective adoption of a new accounting standard for noncontrolling interests in consolidated subsidiaries. | |
| ** | Per share amounts in all periods reflect the 3-for-1 stock split on May 31, 2006. | |
| (a) | Includes after-tax expenses totaling $104 million relating to bond repurchases, retirement benefits, employee severance costs and asset impairments, partially offset by after-tax income totaling $101 million principally relating to resolution of a United States royalty dispute. | |
| (b) | Includes net after-tax expenses of $26 million primarily relating to asset impairments and hurricanes in the Gulf of Mexico. | |
| (c) | Includes 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. | |
| (d) | 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. | |
| (e) | Includes net 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. |
17
Table of Contents
| Item 7. | Management’s 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 refined petroleum products and purchases, markets
and trades, refined petroleum products, natural gas and
electricity.
Net income in 2009 was $740 million compared with
$2,360 million in 2008 and $1,832 million in 2007.
Diluted earnings per share were $2.27 in 2009 compared with
$7.24 in 2008 and $5.74 in 2007. A table of items affecting
comparability between periods is shown on page 20.
Exploration
and Production
The Corporation’s strategy for the E&P segment is to
profitably grow reserves and production in a sustainable and
financially disciplined manner. The Corporation’s total
proved reserves were 1,437 million barrels of oil
equivalent (boe) at December 31, 2009 compared with
1,432 million boe at December 31, 2008 and
1,330 million boe at December 31, 2007. Total proved
reserves additions for 2009 were 157 million boe. These
additions replaced approximately 103% of the Corporation’s
2009 production.
E&P net income was $1,042 million in 2009,
$2,423 million in 2008 and $1,842 million in 2007.
Average realized crude oil selling prices were $51.62 per barrel
in 2009, $82.04 in 2008, and $63.44 in 2007, including the
impact of hedging. The variance in E&P earnings between
years was primarily driven by the fluctuations in average
realized crude oil selling prices.
Production averaged 408,000 barrels of oil equivalent per
day (boepd) in 2009 compared with 381,000 boepd in 2008 and
377,000 boepd in 2007. Production in 2009 increased 27,000 boepd
or 7% from 2008. In 2010, the Corporation currently estimates
total worldwide production will average between 400,000 and
410,000 boepd.
The following is an update of significant E&P activities
during 2009:
| • | In March, production commenced at the Shenzi Field (Hess 28%) in the deepwater Gulf of Mexico. Net production from Shenzi averaged approximately 25,000 boepd for 2009. | |
| • | The Corporation sanctioned the Bakken shale play development in the Williston Basin of North Dakota. The Corporation plans to expand production facilities and increase the rig count to 10 from 3 over the next 18 months, and invest about $1 billion per year over the next five years. As a result, the Corporation projects an increase in net production from approximately 10,000 boepd in 2009 to approximately 80,000 boepd in 2015. | |
| • | In December 2009, the Corporation agreed to a strategic exchange of all of its interests in Gabon and the Clair Field (Hess 9%) in the United Kingdom for an additional 28% interest in the Valhall Field (currently Hess 28%) and an additional 25% interest in the Hod Field (currently Hess 25%), which are both offshore Norway. The transaction which has an effective date of January 1, 2010, is subject to various regulatory and other approvals. In addition, the partners are in discussions regarding the applicability of pre-emption to this transaction. | |
| • | In the Carnarvon basin offshore Western Australia, the Corporation drilled seven exploration wells in 2009 on WA-390-P Block (Hess 100%), six of which were natural gas discoveries. Through December 31, 2009, the Corporation has drilled 11 of the 16 commitment wells on the block, nine of which were natural gas discoveries. The Corporation plans to drill the remaining five commitment wells on the block in 2010. On WA-404-P Block (Hess 50%), the operator completed a successful exploration well in 2009 and plans to drill the remaining eight commitment wells in 2010. In January 2010, the operator announced that the first well of the 2010 program discovered natural gas. | |
| • | At the Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico, engineering and design work for field development progressed during 2009. The Corporation plans to drill an appraisal well on Green Canyon Block 469 in 2010. | |
| • | Two exploration wells were completed on Block BM-S-22 (Hess 40%) offshore Brazil. A notice of discovery was filed for the first well and the second well was expensed. In 2010, the operator of BM-S-22 |
18
Table of Contents
| plans to commence drilling of a third exploration well in the second half of the year. In 2009, the Corporation also drilled an exploration well on BM-ES-30, which was expensed. |
| • | The Corporation successfully flow tested the discovery well in exploration Area 54 (Hess 100%) offshore Libya and subsequently drilled and successfully flow tested a down-dip appraisal well on the block. In 2010, the Corporation plans to reprocess 3D seismic, integrating acquired well information and will continue technical and commercial evaluation of the block. | |
| • | The Corporation acquired rights to explore a total of more than 80,000 net acres in the Marcellus gas shale formation in Pennsylvania. The Corporation is operator and holds a 100% interest on approximately 50,000 acres and holds a 50% non-operated interest in the remaining acreage. Exploration drilling activity is expected to commence in 2010. |
Marketing
and Refining
The Corporation’s strategy for the M&R segment is to
deliver consistent operating performance and generate free cash
flow. M&R net income was $127 million in 2009,
$277 million in 2008 and $300 million in 2007. The
declining earnings were due to lower average margins, which
include the effect of the global economic downturn that began in
2008 and continued into 2009. Refining operations contributed
net income (loss) of $(87) million in 2009,
$73 million in 2008 and $193 million in 2007.
Marketing earnings were $168 million in 2009,
$240 million in 2008 and $83 million in 2007.
Liquidity
and Capital and Exploratory Expenditures
Net cash provided by operating activities was
$3,046 million in 2009, $4,688 million in 2008 and
$3,627 million in 2007, principally reflecting fluctuations
in earnings. At December 31, 2009, cash and cash
equivalents totaled $1,362 million compared with
$908 million at December 31, 2008. Total debt was
$4,467 million at December 31, 2009 compared with
$3,955 million at December 31, 2008. In February 2009,
the Corporation issued $250 million of 5 year senior
unsecured notes with a coupon of 7% and $1 billion of
10 year senior unsecured notes with a coupon of 8.125%. The
majority of the proceeds were used to repay debt under the
revolving credit facility and outstanding borrowings on other
credit facilities. In December 2009, the Corporation issued
$750 million of 30 year bonds at a coupon of 6% and
tendered for $662 million of bonds due in August 2011. The
Corporation completed the repurchase of $546 million of the
2011 bonds in December 2009 and repurchased the remaining
$116 million of these bonds in January 2010. The
Corporation’s debt to capitalization ratio at
December 31, 2009 was 24.8% compared with 24.2% at the end
of 2008.
Capital and exploratory expenditures were as follows for the
years ended December 31:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Exploration and Production
|
||||||||
|
United States
|
$ | 1,200 | $ | 2,164 | ||||
|
International
|
1,927 | 2,477 | ||||||
|
Total Exploration and Production
|
3,127 | 4,641 | ||||||
|
Marketing, Refining and Corporate
|
118 | 187 | ||||||
|
Total Capital and Exploratory Expenditures
|
$ | 3,245 | $ | 4,828 | ||||
|
Exploration expenses charged to income included above:
|
||||||||
|
United States
|
$ | 144 | $ | 211 | ||||
|
International
|
183 | 179 | ||||||
|
Total exploration expenses charged to income included above
|
$ | 327 | $ | 390 | ||||
The Corporation anticipates investing $4.1 billion in
capital and exploratory expenditures in 2010, substantially all
of which relates to E&P operations.
19
Table of Contents
Consolidated
Results of Operations
The after-tax results by major operating activity are summarized
below:
| 2009 | 2008 | 2007 | ||||||||||
|
(Millions of dollars,
|
||||||||||||
| except per share data) | ||||||||||||
|
Exploration and Production
|
$ | 1,042 | $ | 2,423 | $ | 1,842 | ||||||
|
Marketing and Refining
|
127 | 277 | 300 | |||||||||
|
Corporate
|
(205 | ) | (173 | ) | (150 | ) | ||||||
|
Interest expense
|
(224 | ) | (167 | ) | (160 | ) | ||||||
|
Net income attributable to Hess Corporation
|
$ | 740 | $ | 2,360 | $ | 1,832 | ||||||
|
Net income per share — diluted
|
$ | 2.27 | $ | 7.24 | $ | 5.74 | ||||||
The following table summarizes, on an after-tax basis, items of
income (expense) that are included in net income and affect
comparability between periods. The items in the table below are
explained on pages 23 through 25.
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Exploration and Production
|
$ | 45 | $ | (26 | ) | $ | (74 | ) | ||||
|
Marketing and Refining
|
12 | — | 24 | |||||||||
|
Corporate
|
(60 | ) | — | (25 | ) | |||||||
| $ | (3 | ) | $ | (26 | ) | $ | (75 | ) | ||||
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.
Comparison
of Results
Exploration
and Production
Following is a summarized income statement of the
Corporation’s E&P operations:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Sales and other operating revenues*
|
$ | 6,835 | $ | 9,806 | $ | 7,498 | ||||||
|
Other, net
|
207 | (167 | ) | 65 | ||||||||
|
Total revenues and non operating income
|
7,042 | 9,639 | 7,563 | |||||||||
|
Costs and expenses
|
||||||||||||
|
Production expenses, including related taxes
|
1,805 | 1,872 | 1,581 | |||||||||
|
Exploration expenses, including dry holes and lease impairment
|
829 | 725 | 515 | |||||||||
|
General, administrative and other expenses
|
255 | 302 | 257 | |||||||||
|
Depreciation, depletion and amortization
|
2,167 | 1,952 | 1,503 | |||||||||
|
Total costs and expenses
|
5,056 | 4,851 | 3,856 | |||||||||
|
Results of operations before income taxes
|
1,986 | 4,788 | 3,707 | |||||||||
|
Provision for income taxes
|
944 | 2,365 | 1,865 | |||||||||
|
Results of operations attributable to Hess Corporation
|
$ | 1,042 | $ | 2,423 | $ | 1,842 | ||||||
| * | 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. |
20
Table of Contents
After considering the E&P items in the table on
page 23, the remaining changes in E&P earnings are
primarily attributable to changes in selling prices, production
volumes, operating costs, exploration expenses, foreign
exchange, and income taxes, as discussed below.
Selling prices:
Lower average selling
prices reduced E&P revenues by approximately
$4,000 million in 2009 compared with 2008. Higher average
selling prices increased E&P revenues by approximately
$2,100 million in 2008 compared with 2007.
The Corporation’s average selling prices were as follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Crude oil-per barrel (including hedging)
|
||||||||||||
|
United States
|
$ | 60.67 | $ | 96.82 | $ | 69.23 | ||||||
|
Europe
|
47.02 | 78.75 | 60.99 | |||||||||
|
Africa
|
48.91 | 78.72 | 62.04 | |||||||||
|
Asia and other
|
63.01 | 97.07 | 72.17 | |||||||||
|
Worldwide
|
51.62 | 82.04 | 63.44 | |||||||||
|
Crude oil-per barrel (excluding hedging)
|
||||||||||||
|
United States
|
$ | 60.67 | $ | 96.82 | $ | 69.23 | ||||||
|
Europe
|
47.02 | 78.75 | 60.99 | |||||||||
|
Africa
|
60.79 | 93.57 | 71.71 | |||||||||
|
Asia and other
|
63.01 | 97.07 | 72.17 | |||||||||
|
Worldwide
|
56.74 | 89.23 | 67.79 | |||||||||
|
Natural gas liquids-per barrel
|
||||||||||||
|
United States
|
$ | 36.57 | $ | 64.98 | $ | 51.89 | ||||||
|
Europe
|
43.23 | 74.63 | 57.20 | |||||||||
|
Worldwide
|
38.47 | 67.61 | 53.72 | |||||||||
|
Natural gas-per mcf (including hedging)
|
||||||||||||
|
United States
|
$ | 3.36 | $ | 8.61 | $ | 6.67 | ||||||
|
Europe
|
5.15 | 9.44 | 6.13 | |||||||||
|
Asia and other
|
5.06 | 5.24 | 4.71 | |||||||||
|
Worldwide
|
4.85 | 7.17 | 5.60 | |||||||||
|
Natural gas-per mcf (excluding hedging)
|
||||||||||||
|
United States
|
$ | 3.36 | $ | 8.61 | $ | 6.67 | ||||||
|
Europe
|
5.15 | 9.79 | 6.13 | |||||||||
|
Asia and other
|
5.06 | 5.24 | 4.71 | |||||||||
|
Worldwide
|
4.85 | 7.30 | 5.60 | |||||||||
In October 2008, the Corporation closed its Brent crude oil
hedges, covering 24,000 barrels per day from 2009 though
2012, by entering into offsetting contracts with the same
counterparty. The deferred after-tax loss as of the date the
hedge positions were closed will be recorded in earnings as the
contracts mature. The estimated annual after-tax loss from the
closed positions will be approximately $335 million from
2010 through 2012. Crude oil hedges reduced E&P earnings by
$337 million ($533 million before income taxes) in
2009. Crude oil and natural gas hedges reduced E&P earnings
by $423 million ($685 million before income taxes) in
2008 and $244 million ($399 million before income
taxes) in 2007.
Production and sales volumes:
The
Corporation’s crude oil and natural gas production was
408,000 boepd in 2009 compared with 381,000 boepd in 2008 and
377,000 boepd in 2007. The Corporation currently estimates that
its 2010 production will average between 400,000 and 410,000
boepd.
21
Table of Contents
The Corporation’s net daily worldwide production was as
follows (in thousands):
| 2009 | 2008 | 2007 | ||||||||||
|
Crude oil (barrels per day)
|
||||||||||||
|
United States
|
60 | 32 | 31 | |||||||||
|
Europe
|
83 | 83 | 93 | |||||||||
|
Africa
|
120 | 124 | 115 | |||||||||
|
Asia and other
|
16 | 13 | 21 | |||||||||
|
Total
|
279 | 252 | 260 | |||||||||
|
Natural gas liquids (barrels per day)
|
||||||||||||
|
United States
|
11 | 10 | 10 | |||||||||
|
Europe
|
3 | 4 | 5 | |||||||||
|
Total
|
14 | 14 | 15 | |||||||||
|
Natural gas (mcf per day)
|
||||||||||||
|
United States
|
93 | 78 | 88 | |||||||||
|
Europe
|
151 | 255 | 259 | |||||||||
|
Asia and other
|
446 | 356 | 266 | |||||||||
|
Total
|
690 | 689 | 613 | |||||||||
|
Barrels of oil equivalent* (barrels per day)
|
408 | 381 | 377 | |||||||||
| * | 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 in the United States was higher in 2009 compared
with 2008, primarily due to new production from the Shenzi Field
and production resuming after the 2008 hurricanes. Crude oil
production was slightly higher in 2008 compared with 2007,
principally due to production from new wells in North Dakota and
the deepwater Gulf of Mexico, largely offset by the impact of
hurricanes in the Gulf of Mexico. Natural gas production was
lower in 2008 compared to 2007, primarily reflecting hurricane
downtime and natural decline. Hurricane impacts reduced full
year 2008 production by an estimated 7,000 boepd.
Europe:
Crude oil production was
comparable in 2009 and 2008, as higher production in Russia
offset lower production in the United Kingdom North Sea. Crude
oil production in 2008 was lower than in 2007, due to temporary
shut-ins at three North Sea fields, the cessation of production
at the Fife, Fergus, Flora and Angus fields, and natural
decline. These decreases were partially offset by increased
production in Russia. Natural gas production was lower in 2009
compared with 2008, primarily due to decline at the Atlantic and
Cromarty fields.
Africa:
Crude oil production decreased
in 2009 compared with 2008 primarily due to lower production
from the Ceiba Field. Crude oil production increased in 2008
compared with 2007, primarily due to higher production at the
Okume Complex, partially offset by a lower entitlement to
Algerian production.
Asia and other:
Natural gas production
in 2009 was higher than in 2008, primarily due to a full year of
Phase 2 gas sales from the Joint Development Area of
Malaysia/Thailand (JDA). Natural gas production increased in
2008 compared with 2007 due to increased production from Block
A-18
in the
JDA and a full year of production from the Ujung Pangkah Field
in Indonesia. The decrease in crude oil production in 2008 from
2007 principally reflects changes to the Corporation’s
entitlement to production in Azerbaijan.
Sales volumes:
Higher sales volumes and
other operating revenues increased revenue by approximately
$1,030 million in 2009 compared with 2008 and
$200 million in 2008 compared with 2007.
Operating costs and depreciation, depletion and
amortization:
Excluding the impact of items affecting
comparability explained on page 23, cash operating costs,
consisting of production expenses and general and administrative
expenses, decreased by $119 million in 2009 and increased
by $321 million in 2008 compared with the corresponding
amounts in the prior years. The decrease in 2009 compared with
2008 was primarily due to lower
22
Table of Contents
production taxes (due to lower realized selling prices), the
cessation of production at several North Sea fields, the
favorable impact of foreign exchange rates and cost savings
initiatives, partially offset by the impact of higher production
volumes. The increase in costs in 2008 compared to 2007 was
primarily due to increased production taxes (due to higher
realized selling prices), increased cost of services and
materials and higher employee costs.
Excluding the impact of items affecting comparability,
depreciation, depletion and amortization charges increased by
$192 million in 2009 and $531 million in 2008,
compared with the corresponding amounts in the prior years. The
increases in 2009 and 2008 were primarily due to higher
production volumes and per barrel costs, reflecting higher
finding and development costs.
Excluding items affecting comparability between periods, unit
costs were as follows. Cash operating costs per barrel of oil
equivalent were $13.70 in 2009, $15.49 in 2008 and $13.36 in
2007. Cash operating costs in 2010 are estimated to be in the
range of $15 to $16 per barrel of oil equivalent. Depreciation,
depletion and amortization costs per barrel of oil equivalent
were $14.19 in 2009, $13.79 in 2008 and $10.11 in 2007.
Depreciation, depletion and amortization costs for 2010 are
estimated to be in the range of $14.50 to $15.50 per barrel of
oil equivalent.
Exploration expenses:
Exploration
expenses increased in 2009 from 2008, primarily due to higher
dry hole costs and lease amortization, partially offset by lower
geological and seismic expense. Exploration expenses increased
in 2008 compared to 2007, mainly due to higher dry hole costs.
Income taxes:
Excluding the impact of
items affecting comparability, the effective income tax rates
for E&P operations were 48% in 2009, 49% in 2008 and 50% in
2007. The effective income tax rate for E&P operations in
2010 is estimated to be in the range of 47% to 51%.
Foreign Exchange:
The after-tax foreign
currency losses were $10 million in 2009, $80 million
in 2008 and $7 million in 2007. The foreign currency loss
in 2008 reflects the net effect of significant exchange rate
movements in the fourth quarter of 2008 on the remeasurement of
assets, liabilities and foreign currency forward contracts by
certain foreign businesses.
Reported E&P earnings include the following items affecting
comparability of income (expense) before and after income taxes:
| Before Income Taxes | After Income Taxes | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Royalty dispute resolution
|
$ | 143 | $ | — | $ | — | $ | 89 | $ | — | $ | — | ||||||||||||
|
Gains from asset sales
|
— | — | 21 | — | — | 15 | ||||||||||||||||||
|
Reductions in carrying values of assets
|
(77 | ) | (30 | ) | (112 | ) | (44 | ) | (17 | ) | (56 | ) | ||||||||||||
|
Hurricane related costs
|
— | (15 | ) | — | — | (9 | ) | — | ||||||||||||||||
|
Estimated production imbalance settlements
|
— | — | (64 | ) | — | — | (33 | ) | ||||||||||||||||
| $ | 66 | $ | (45 | ) | $ | (155 | ) | $ | 45 | $ | (26 | ) | $ | (74 | ) | |||||||||
2009:
In October 2009, the U.S. Supreme
Court decided it would not review the decision of the
5th Circuit Court of Appeals against the U.S. Minerals
Management Service relating to royalty relief under the Deep
Water Royalty Relief Act of 1995. As a result, the Corporation
recognized an after-tax gain of $89 million to reverse all
previously recorded royalties covering the periods from 2003 to
2009. The pre-tax gain of $143 million is reported in
Other, net within the Statement of Consolidated Income.
After-tax charges of $44 million ($77 million before
income taxes) were recorded to impair the carrying values of
production equipment and two short-lived fields in the United
Kingdom North Sea, and to write down materials inventories in
Equatorial Guinea and the United States. The pre-tax amount of
the impairment charges totaling $52 million were reported
in Depreciation, depletion and amortization and the majority of
the $25 million in inventory write downs was reported in
Production expenses in the Statement of Consolidated Income.
23
Table of Contents
2008:
The charge for asset impairments relates
to mature fields in the United States and the United Kingdom
North Sea. The hurricane costs relate to expenses associated
with Hurricanes Gustav and Ike in the Gulf of Mexico and are
recorded in Production expenses.
2007:
The gain from asset sales relates to the
sale of the Corporation’s interests in the Scott and
Telford fields in the United Kingdom North Sea. The charge for
asset impairments relates to two mature fields also in the
United Kingdom North Sea. 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.
The Corporation’s future E&P earnings may be impacted
by external factors, such as volatility in the selling prices of
crude oil and natural gas, reserve and production changes,
political risk, industry costs, exploration expenses, the
effects of weather and changes in foreign exchange and income
tax rates.
Marketing
and Refining
Earnings from M&R activities amounted to $127 million
in 2009, $277 million in 2008 and $300 million in
2007. Excluding the items affecting comparability reflected in
the table on page 20 and discussed below, the earnings were
$115 million, $277 million and $276 million,
respectively.
Refining:
Refining earnings (losses),
which consist of the Corporation’s share of HOVENSA’s
results, Port Reading earnings, interest income on a note
receivable from PDVSA and results of other miscellaneous
operating activities, were $(87) million in 2009 (including
a benefit of $12 million due to an income tax adjustment),
$73 million in 2008, and $193 million in 2007.
The Corporation’s share of HOVENSA’s results was a
loss of $141 million ($229 million before income
taxes) in 2009, and income of $27 million ($44 million
before income taxes) in 2008 and $108 million
($176 million before income taxes) in 2007. The declining
earnings were principally due to lower refining margins. The
2009 and 2008 utilization rates for HOVENSA reflect weaker
refining margins and planned and unplanned maintenance. The 2008
utilization rates also reflect a refinery wide shut down for
Hurricane Omar. In 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 January 2010, HOVENSA commenced a turnaround of
its FCC unit which is expected to take approximately
40 days. The Corporation’s estimated share of
HOVENSA’s turnaround expenses after income taxes is
expected to be approximately $20 million.
Cash distributions received by the Corporation from HOVENSA were
$50 million in 2008 and $300 million in 2007. In 2009,
the remaining balance on the note issued by PDVSA at inception
of the joint venture was fully repaid.
Other after-tax refining earnings, principally from Port Reading
operations, were $43 million in both 2009 and 2008 and
$79 million in 2007, reflecting lower margins. The
Corporation is planning a turnaround for the Port Reading
refining facility in the second quarter of 2010, which is
expected to take approximately 35 days. The estimated
after-tax expenses for the Port Reading turnaround are
approximately $25 million.
The following table summarizes refinery utilization rates:
|
Refinery
|
Refinery Utilization | |||||||||||||||
| Capacity | 2009 | 2008 | 2007 | |||||||||||||
|
(Thousands of
|
||||||||||||||||
| barrels per day) | ||||||||||||||||
|
HOVENSA
|
||||||||||||||||
|
Crude
|
500 | 80.3% | 88.2% | 90.8% | ||||||||||||
|
Fluid catalytic cracker
|
150 | 70.2% | 72.7% | 87.1% | ||||||||||||
|
Coker
|
58 | 81.6% | 92.4% | 83.4% | ||||||||||||
|
Port Reading
|
70 | 90.2% | 90.7% | 93.2% | ||||||||||||
Marketing:
Marketing operations, which
consist principally of retail gasoline and energy marketing
activities, generated income of $168 million in 2009,
$240 million in 2008 and $83 million in 2007,
including income from the liquidation of LIFO inventories in
2007 totaling $24 million ($38 million before income
taxes).
24
Table of Contents
The decrease in earnings in 2009 compared with 2008 reflects
lower margins in a weak economic environment. The increase in
2008 compared with 2007 primarily reflects higher margins on
refined product sales, including sales of retail gasoline
operations.
The table below summarizes marketing sales volumes:
| 2009 | 2008 | 2007 | ||||||||||
|
Refined product sales (thousands of barrels per day)
|
473 | 472 | 451 | |||||||||
|
Natural gas (thousands of mcf per day)
|
2,010 | 1,955 | 1,890 | |||||||||
|
Electricity (megawatts round the clock)
|
4,306 | 3,152 | 2,821 | |||||||||
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 Corporation’s after-tax results from
trading activities, including its share of the results of the
trading partnership, amounted to earnings of $46 million in
2009, a loss of $36 million in 2008 and earnings of
$24 million in 2007.
Marketing expenses decreased in 2009 as compared with 2008,
principally reflecting lower retail credit card fees. Marketing
expenses increased in 2008 compared with 2007, due to growth in
energy marketing activities, higher retail credit card fees, and
increased transportation costs.
The Corporation’s future M&R earnings may be impacted
by external factors, such as volatility in margins, competitive
industry conditions, government regulations, credit risk, and
supply and demand factors, including the effects of weather.
Corporate
The following table summarizes corporate expenses:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Corporate expenses
|
$ | 227 | $ | 260 | $ | 187 | ||||||
|
Income taxes (benefits)
|
(82 | ) | (87 | ) | (62 | ) | ||||||
|
After-tax corporate expenses
|
145 | 173 | 125 | |||||||||
|
Items affecting comparability between periods, after tax
|
60 | — | 25 | |||||||||
|
Net corporate expenses
|
$ | 205 | $ | 173 | $ | 150 | ||||||
Excluding items affecting comparability between periods, the
decrease in corporate expenses in 2009 compared with 2008
primarily reflects gains on supplemental pension related
investments, together with lower employee and professional
costs, partly offset by higher bank facility fees. The increase
in corporate expenses in 2008 compared with 2007 primarily
reflects losses on supplemental pension related investments and
higher employee and professional costs. After-tax corporate
expenses in 2010 are estimated to be in the range of $160 to
$170 million.
In 2009, the Corporation recorded after-tax charges of
$34 million ($54 million before income taxes) related
to the repurchase of $546 million in notes that were
scheduled to mature in 2011 and $26 million
($42 million before income taxes) relating to retirement
benefits and employee severance costs. The pre-tax charge in
connection with the debt repurchase was recorded in Other, net,
and the pre-tax amount of the retirement benefits and severance
costs was recorded in General and administrative expenses within
the Statement of Consolidated Income. In 2007, Corporate
expenses included a charge of $25 million ($40 million
before income taxes) related to MTBE litigation. The pre-tax
amount of this charge was recorded in General and administrative
expenses.
25
Table of Contents
Interest
Interest expense was as follows:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Total interest incurred
|
$ | 366 | $ | 274 | $ | 306 | ||||||
|
Less capitalized interest
|
6 | 7 | 50 | |||||||||
|
Interest expense before income taxes
|
360 | 267 | 256 | |||||||||
|
Less income taxes
|
136 | 100 | 96 | |||||||||
|
After-tax interest expense
|
$ | 224 | $ | 167 | $ | 160 | ||||||
The increase in interest expense primarily reflects higher debt
and fees for letters of credit. The decrease in capitalized
interest in 2009 and 2008 compared to 2007 reflects the
completion of several development projects in 2007. After-tax
interest expense in 2010 is expected to be in the range of $220
to $230 million.
Sales
and Other Operating Revenues
Sales and other operating revenues totaled $29,614 million
in 2009, a decrease of 28% compared with 2008. In 2008, sales
and other operating revenues totaled $41,134 million, an
increase of 30% compared with 2007. The fluctuations in each
year primarily reflect changes in crude oil and refined product
selling prices.
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
Corporation’s liquidity and capital resources as of
December 31:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Cash and cash equivalents
|
$ | 1,362 | $ | 908 | ||||
|
Current portion of long-term debt
|
$ | 148 | $ | 143 | ||||
|
Total debt
|
$ | 4,467 | $ | 3,955 | ||||
|
Total equity
|
$ | 13,528 | $ | 12,391 | ||||
|
Debt to capitalization ratio*
|
24.8 | % | 24.2 | % | ||||
| * | Total debt as a percentage of the sum of total debt plus equity. |
Cash
Flows
The following table sets forth a summary of the
Corporation’s cash flows:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$ | 3,046 | $ | 4,688 | $ | 3,627 | ||||||
|
Investing activities
|
(2,924 | ) | (4,444 | ) | (3,474 | ) | ||||||
|
Financing activities
|
332 | 57 | 71 | |||||||||
|
Net increase in cash and cash equivalents
|
$ | 454 | $ | 301 | $ | 224 | ||||||
Operating Activities:
Net cash provided
by operating activities, including changes in operating assets
and liabilities, was $3,046 million in 2009 compared with
$4,688 million in 2008, reflecting lower earnings.
Operating
26
Table of Contents
cash flow increased to $4,688 million in 2008 from
$3,627 million in 2007, primarily reflecting increased
earnings. The Corporation received cash distributions from
HOVENSA of $50 million in 2008 and $300 million in
2007.
Investing Activities:
The following
table summarizes the Corporation’s capital expenditures:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Exploration and Production
|
||||||||||||
|
Exploration
|
$ | 611 | $ | 744 | $ | 371 | ||||||
|
Production and development
|
1,927 | 2,523 | 2,605 | |||||||||
|
Acquisitions (including leaseholds)
|
262 | 984 | 462 | |||||||||
| 2,800 | 4,251 | 3,438 | ||||||||||
|
Marketing, Refining and Corporate
|
118 | 187 | 140 | |||||||||
|
Total
|
$ | 2,918 | $ | 4,438 | $ | 3,578 | ||||||
Capital expenditures in 2009 include acquisitions of
$188 million for unproved leaseholds and $74 million
for a 50% interest in blocks PM301 and PM302 in Malaysia, which
are adjacent to Block
A-18
of the
JDA. Capital expenditures in 2008 include $600 million for
leasehold acquisitions in the United States and
$210 million for the acquisition of the remaining 22.5%
interest in the Corporation’s Gabonese subsidiary. In 2008,
the Corporation also selectively expanded its energy marketing
business by acquiring fuel oil, natural gas, and electricity
customer accounts, and a terminal and related assets, for an
aggregate of approximately $100 million. In 2007, capital
expenditures include the acquisition of a 28% interest in the
Genghis Khan Field in the deepwater Gulf of Mexico for
$371 million.
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.
Financing Activities:
During 2009, net
proceeds from borrowings were $447 million. In February
2009, the Corporation issued $250 million of 5 year
senior unsecured notes with a coupon of 7% and $1 billion
of 10 year senior unsecured notes with a coupon of 8.125%.
The majority of the proceeds were used to repay debt under the
revolving credit facility and outstanding borrowings on other
credit facilities. In December 2009, the Corporation issued
$750 million of 30 year bonds with a coupon of 6% and
tendered for the $662 million of bonds due in August 2011.
The Corporation completed the repurchase of $546 million of
the 2011 bonds in December 2009. The remaining $116 million
of 2011 bonds, classified as Current maturities of long term
debt at December 31, 2009, was redeemed in January 2010,
resulting in a charge of approximately $11 million
($7 million after income taxes). During 2008, net
repayments of debt were $32 million, compared with net
borrowings of $208 million in 2007.
Total common stock dividends paid were $131 million,
$130 million and $127 million in 2009, 2008 and 2007,
respectively. The Corporation received net proceeds from the
exercise of stock options, including related income tax
benefits, of $18 million, $340 million and
$111 million in 2009, 2008 and 2007, respectively.
Future
Capital Requirements and Resources
The Corporation anticipates investing a total of approximately
$4.1 billion in capital and exploratory expenditures during
2010, substantially all of which is targeted for E&P
operations. In the Corporation’s M&R operations,
refining margins are currently weak, which have adversely
affected HOVENSA’s liquidity position. The Corporation
intends to provide its share of any necessary financial support
for HOVENSA. The Corporation expects to fund its 2010
operations, including capital expenditures, dividends, pension
contributions and required debt repayments and any necessary
financial support for HOVENSA, with existing cash on-hand, cash
flow from operations and its available credit facilities. Crude
oil prices, natural gas prices and refining margins are volatile
and difficult to predict. In addition, unplanned increases in
the Corporation’s capital expenditure program could occur.
If conditions were to change, such as a significant decrease in
commodity prices or an unexpected increase in capital
expenditures, the Corporation would take steps to protect its
financial flexibility and may pursue other sources of liquidity,
including the issuance of debt securities, the issuance of
equity securities,
and/or
asset
sales.
27
Table of Contents
The table below summarizes the capacity, usage, and available
capacity of the Corporation’s borrowing and letter of
credit facilities at December 31, 2009 (in millions):
|
Expiration
|
Letters of
|
Available
|
||||||||||||||||||||
| Date | Capacity | Borrowings | Credit Issued | Total Used | Capacity | |||||||||||||||||
|
Revolving credit facility
|
May 2012(a) | $ | 3,000 | $ | — | $ | — | $ | — | $ | 3,000 | |||||||||||
|
Asset backed credit facility
|
July 2010(b) | 741 | — | 500 | 500 | 241 | ||||||||||||||||
|
Committed lines
|
Various(c) | 2,115 | — | 1,155 | 1,155 | 960 | ||||||||||||||||
|
Uncommitted lines
|
Various(c) | 1,192 | — | 1,192 | 1,192 | — | ||||||||||||||||
|
Total
|
$ | 7,048 | $ | — | $ | 2,847 | $ | 2,847 | $ | 4,201 | ||||||||||||
| (a) | $75 million expires in May 2011. | |
| (b) | Total capacity of $1.0 billion subject to the amount of eligible receivables posted as collateral. | |
| (c) | Committed and uncommitted lines have expiration dates primarily through 2010. |
The Corporation maintains a $3.0 billion syndicated,
revolving credit facility (the facility), of which
$2,925 million is committed through May 2012. The facility
can be used for borrowings and letters of credit. At
December 31, 2009, available capacity under the facility
was $3.0 billion. The Corporation has a 364 day
asset-backed credit facility securitized by certain accounts
receivable from its M&R operations. At December 31,
2009, under the terms of this financing arrangement, the
Corporation has the ability to borrow or issue letters of credit
of up to $1.0 billion, subject to the availability of
sufficient levels of eligible receivables. At December 31,
2009, outstanding letters of credit under this facility were
collateralized by a total of $1,326 million of accounts
receivable, which are held by a wholly owned subsidiary. These
receivables are only available to pay the general obligations of
the Corporation after satisfaction of the outstanding
obligations under the asset backed facility.
The Corporation also has a shelf registration under which it may
issue additional debt securities, warrants, common stock or
preferred stock.
A loan agreement covenant based on the Corporation’s debt
to capitalization ratio allows the Corporation to borrow up to
an additional $18.1 billion for the construction or
acquisition of assets at December 31, 2009. The Corporation
has the ability to borrow up to an additional $3.7 billion
of secured debt at December 31, 2009 under the loan
agreement covenants.
The Corporation’s $2,847 million in letters of credit
outstanding at December 31, 2009 were primarily issued to
satisfy margin requirements. See also Note 14, Risk
Management and Trading Activities.
Credit
Ratings
There are three major credit rating agencies that rate the
Corporation’s debt. All three agencies have currently
assigned an investment grade rating to the Corporation’s
debt. The interest rates and facility fees charged on some of
the Corporation’s credit facilities, as well as margin
requirements from risk management and trading counterparties,
are subject to adjustment if the Corporation’s credit
rating changes.
28
Table of Contents
Contractual
Obligations and Contingencies
Following is a table showing aggregated information about
certain contractual obligations at December 31, 2009:
| Payments Due by Period | ||||||||||||||||||||
|
2011 and
|
2013 and
|
|||||||||||||||||||
| Total | 2010 | 2012 | 2014 | Thereafter | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
Long-term debt*
|
$ | 4,467 | $ | 148 | $ | 66 | $ | 370 | $ | 3,883 | ||||||||||
|
Operating leases
|
3,282 | 482 | 695 | 677 | 1,428 | |||||||||||||||
|
Purchase obligations
|
||||||||||||||||||||
|
Supply commitments**
|
37,870 | 13,158 | 12,546 | 12,118 | 48 | |||||||||||||||
|
Capital expenditures
|
939 | 745 | 191 | 2 | 1 | |||||||||||||||
|
Operating expenses
|
937 | 457 | 276 | 70 | 134 | |||||||||||||||
|
Other long-term liabilities
|
2,095 | 145 | 366 | 199 | 1,385 | |||||||||||||||
| * | At December 31, 2009, the Corporation’s debt bears interest at a weighted average rate of 7.3%. | |
| ** | The Corporation intends to continue purchasing refined product supply from HOVENSA. Estimated future purchases amount to approximately $6.0 billion annually using year-end 2009 prices, which have been included in the table through 2014. |
In the preceding table, the Corporation’s supply
commitments include its estimated purchases of 50% of
HOVENSA’s 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 Corporation’s 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 to supply
contracted customers in its energy marketing business. These
commitments were computed based predominately on year-end market
prices.
The table also reflects future capital expenditures, including
the portion of the Corporation’s planned $4.1 billion
capital investment program for 2010 that is contractually
committed at December 31, 2009. 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, 2009, including asset retirement obligations,
pension plan liabilities 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. 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. The total
payments under this five year contract are expected to be
approximately $950 million. The Corporation took delivery
of the drillship in the fourth quarter of 2009.
The Corporation has a contingent purchase obligation, expiring
in April 2012, to acquire the remaining interest in WilcoHess, a
retail gasoline station joint venture, for approximately
$184 million as of December 31, 2009.
The Corporation guarantees the payment of up to 50% of
HOVENSA’s crude oil purchases from certain suppliers other
than PDVSA. The amount of the Corporation’s guarantee
fluctuates based on the volume of crude oil purchased and
related prices and at December 31, 2009 it amounted to
$121 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.
29
Table of Contents
The Corporation is contingently liable under letters of credit
and under guarantees of the debt of other entities directly
related to its business at December 31, 2009 as shown below:
| Total | ||||
|
(Millions of
|
||||
| dollars) | ||||
|
Letters of credit
|
$ | 100 | ||
|
Guarantees
|
136 | |||
| $ | 236 | |||
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
$412 million at December 31, 2009 compared with
$491 million at December 31, 2008. The
Corporation’s December 31, 2009 debt to capitalization
ratio would increase from 24.8% to 26.5% if these leases were
included as debt.
See also Note 4, Refining Joint Venture, and Note 15,
Guarantees and Contingencies, in the notes to the financial
statements.
Foreign
Operations
The Corporation conducts exploration and production activities
outside the United States, principally in Algeria, Australia,
Azerbaijan, Brazil, Colombia, Denmark, Egypt, Equatorial Guinea,
Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Peru, Russia,
Thailand, and the United Kingdom. Therefore, the Corporation is
subject to the risks associated with foreign operations,
including political risk, tax law changes, and currency risk.
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 Corporation’s balance sheet
and revenues and expenses on the income statement. The
accounting methods used can affect net income, equity and
various financial statement ratios. However, the
Corporation’s 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
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
SEC revised its oil and gas reserve estimation and disclosure
requirements effective for year-end 2009 reporting. In addition,
the Financial Accounting Standards Board (FASB) revised its
accounting standard on oil and gas reserve estimation and
disclosures. The determination of estimated
30
Table of Contents
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.
For reserves to be booked as proved they must be determined with
reasonable certainty to be economically producible from known
reservoirs under existing economic conditions, operating methods
and government regulations. In addition, 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 Corporation maintains its
own internal reserve estimates that are calculated by technical
staff that work directly with the oil and gas properties. The
Corporation’s 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
review. The Corporation also engaged an independent third party
consulting firm to audit approximately 80% of the
Corporation’s total proved reserves.
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 that 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 management’s best estimate of
future prices, which is determined with reference to recent
historical prices and published forward prices, applied to
projected production volumes and discounted at a risk-adjusted
rate. 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 historical twelve month average prices.
The Corporation’s impairment tests of long-lived E&P
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.
The Corporation’s goodwill is tested for impairment at a
reporting unit level, which is an operating segment or one level
below an operating segment. The impairment test is conducted
annually in the fourth quarter or when events or changes in
circumstances indicate that the carrying amount of the goodwill
may not be recoverable. 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
Corporation’s goodwill is assigned to the E&P
operating segment and it expects that the benefits of goodwill
will be recovered through the operation of that segment.
The Corporation’s fair value estimate of the E&P
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.
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Table of Contents
The determination of the fair value of the E&P 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 E&P segment that could result in an impairment of
goodwill.
As 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
E&P segment.
Income Taxes:
Judgments are required in
the determination and recognition of income tax assets and
liabilities in the financial statements. These judgments 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 or credit
carryforwards in several jurisdictions, including the United
States, and has recorded deferred tax assets for those losses
and credits. 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 and credit carryforwards,
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 Corporation’s internal business
forecasts. Additionally, the Corporation has income taxes which
have been deferred on intercompany transactions eliminated in
consolidation related to transfers of property, plant and
equipment remaining within the consolidated group. The
amortization of these income taxes deferred on intercompany
transactions will occur ratably with the recovery through
depletion and depreciation of the carrying value of these
assets. The Corporation does not provide for deferred
U.S. income taxes for that portion of undistributed
earnings of foreign subsidiaries that are indefinitely
reinvested in foreign operations.
Fair Value Measurements:
The
Corporation’s derivative instruments and supplemental
pension plan investments are recorded at fair value, with
changes in fair value recognized in earnings or other
comprehensive income each period. The Corporation uses various
valuation approaches in determining fair value, including the
market and income approaches. The Corporation’s fair value
measurements also include non-performance risk and time value of
money considerations. Counterparty credit is considered for
receivable balances, and the Corporation’s credit is
considered for accrued liabilities.
The Corporation determines fair value in accordance with the
FASB fair value measurements accounting standard which
established a hierarchy that categorizes the sources of inputs,
which generally range from quoted prices for identical
instruments in a principal trading market (Level 1) to
estimates determined using related market data (Level 3).
Multiple inputs may be used to measure fair value, however, the
level of fair value is based on the lowest significant input
level within this fair value hierarchy. Inputs include
discounted cash flow calculations and other unobservable data.
The Corporation also records certain nonfinancial assets and
liabilities at fair value. These fair value measurements include
assets and liabilities recorded in connection with business
combinations, the initial recognition of asset retirement
obligations and long-lived assets and goodwill measured at fair
value in an impairment assessment.
Details on the methods and assumptions used to determine the
fair values are as follows
:
Fair value measurements based on Level 1
inputs:
Measurements that are most observable
are based on quoted prices of identical instruments obtained
from the principal markets in which they are traded. Closing
prices are both readily available and representative of fair
value. Market transactions occur with sufficient frequency and
volume to assure liquidity. The fair value of certain of the
Corporation’s exchange traded futures and options are
considered Level 1.
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Fair value measurements based on Level 2
inputs:
Measurements derived indirectly from
observable inputs or from quoted prices from markets that are
less liquid are considered Level 2. Measurements based on
Level 2 inputs include
over-the-counter
derivative instruments that are priced on an exchange traded
curve but have contractual terms that are not identical to
exchange traded contracts. The Corporation utilizes fair value
measurements based on Level 2 inputs for certain forwards,
swaps and options. The liability related to the
Corporation’s crude oil hedges is classified as
Level 2.
Fair value measurements based on Level 3
inputs:
Measurements that are least
observable are estimated from related market data determined
from sources with little or no market activity for comparable
contracts or are positions with longer durations. For example,
in its energy marketing business, the Corporation sells natural
gas and electricity to customers and offsets the price exposure
by purchasing forward contracts. The fair value of these sales
and purchases may be based on specific prices at less liquid
delivered locations, which are classified as Level 3. Fair
values determined using discounted cash flows are also
classified as Level 3.
Derivatives:
The Corporation utilizes
derivative instruments for both risk management and trading
activities. In risk management 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, as well as changes in interest and 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
Corporation’s balance sheet. The Corporation’s 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 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 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.
Retirement Plans:
The Corporation has
funded non-contributory defined benefit pension plans and an
unfunded supplemental pension plan. The Corporation recognizes
on the balance sheet the net change in the funded status of the
projected benefit obligation for these plans.
The determination of the obligations and expenses related to
these plans are based on several actuarial assumptions, the most
significant of which relate to the discount rate for measuring
the present value of future plan obligations; expected long-term
rates of return on plan assets; and rate of future increases in
compensation levels. These assumptions represent estimates made
by the Corporation, some of which can be affected by external
factors. For example, the discount rate used to estimate the
Corporation’s projected benefit obligation is based on a
portfolio of high-quality, fixed-income debt instruments with
maturities that approximate the expected payment of plan
obligations, while the expected return on plan assets is
developed from the expected future returns for each asset
category, weighted by the target allocation of pension assets to
that asset category. Changes in these assumptions can have a
material impact on the amounts reported in the
Corporation’s financial statements.
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
33
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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 Corporation’s 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.
Changes
in Accounting Policies
The FASB Accounting Standards Codification (ASC) became
effective on July 1, 2009. The ASC combined multiple
sources of authoritative accounting literature into a single
source of authoritative GAAP organized by accounting topic.
Since the ASC was not intended to change existing GAAP, the only
impact on the Corporation’s financial statements was that
specific references to accounting principles have been changed
to refer to the ASC.
Effective January 1, 2009, the Corporation adopted the FASB
accounting standard for the accounting for and reporting of
noncontrolling interests in a consolidated subsidiary (ASC
810 — Consolidation, originally issued as
FAS 160,
Noncontrolling Interests in Consolidated
Financial Statements, an amendment of ARB No. 51
). As
required, the Corporation retrospectively applied the
presentation and disclosure requirements of this standard. At
December 31, 2009 and December 31, 2008 noncontrolling
interests of $144 million and $84 million,
respectively, have been classified as a component of equity.
Prior to adoption, noncontrolling interests were classified in
Other liabilities. Net income (loss) attributable to the
noncontrolling interests must also be separately reported in the
Statement of Consolidated Income. Certain other amounts in the
consolidated financial statements and footnotes have been
reclassified to conform with the presentation requirements of
this standard.
Effective January 1, 2009, the Corporation adopted the FASB
accounting standard that expanded the qualitative, quantitative
and credit risk disclosure requirements related to an
entity’s use of derivative instruments (ASC 815 —
Derivatives and Hedging, originally issued as FAS 161,
Disclosures about Derivative Instruments and Hedging
Activities
). See Note 14, Risk Management and Trading
Activities, for these disclosures.
Effective January 1, 2009, the Corporation also adopted the
FASB staff position that requires the application of the fair
value measurement and disclosure provisions to nonfinancial
assets and liabilities that are measured at fair value on a
nonrecurring basis (ASC 820 — Fair Value Measurements
and Disclosures, originally issued as FASB Staff Position
No. 157-2,
Effective Date of FASB Statement No. 157
). Such fair
value measurements are determined based on the same fair value
hierarchy of inputs required to measure the fair value of
financial assets and liabilities. The impact of this accounting
standard was not material to the Corporation’s consolidated
financial statements.
Effective June 30, 2009, the Corporation adopted the FASB
accounting standard which provides guidance on the accounting
for and disclosure of events that occur after the balance sheet
date but before financial statements are issued (ASC
855 — Subsequent Events, originally issued as
FAS 165,
Subsequent Events
). The adoption of this
standard did not impact the Corporation’s existing practice
of evaluating subsequent events through the date the financial
statements are issued.
In January 2010, the FASB adopted an accounting standards update
(ASU) Extractive Activities — Oil and Gas (ASC
932 — Oil and Gas Reserve Estimation and Disclosures)
which is effective for financial statements for the year ended
December 31, 2009 and amends the requirements for oil and
gas reserve estimation and disclosures. The objective of the ASU
was to align accounting standards with the previously issued SEC
requirements on oil and gas reserve estimation and disclosure.
The main provisions of the ASU are to expand the definition of
oil and gas producing activities to include the extraction of
resources which are saleable as synthetic oil or gas, to change
the price assumption used for reserve estimation and future cash
flows to a twelve month average from the year-end
34
Table of Contents
price and to amend the geographic disclosure requirements for
reporting reserves and other supplementary oil and gas data. See
the Supplementary Oil and Gas Data for these disclosures.
Recently
Issued Accounting Standards
In June 2009, the FASB amended existing accounting standards to
eliminate the concept of a qualifying special-purpose entity
(ASC 860 — Transfers and Servicing, originally issued
as FAS 166,
Accounting for Transfers of Financial
Assets — an amendment of FASB Statement
No. 140
), which did not require consolidation under
existing GAAP. The FASB also amended existing accounting
standards to limit the circumstances in which transferred
financial assets should be derecognized (ASC 810 —
Consolidation, originally issued as FAS 167,
Amendments
to FASB Interpretation No. FIN 46(R)
). The amended
standards require additional analysis of variable interest
entities to determine if consolidation is necessary. The
adoption of these standards will not have a material impact on
the Corporation’s financial statements. As required, the
Corporation will adopt the provisions of these standards
effective January 1, 2010.
Environment,
Health and Safety
The Corporation has a values-based, socially-responsible
strategy focused on improving environment, health and safety
performance and making a positive impact on communities where it
does business. The strategy is reflected in the
Corporation’s environment, health, safety and social
responsibility (EHS & SR) policies and by environment
and safety management systems that help protect the
Corporation’s workforce, customers and local communities.
The Corporation’s 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
Corporation’s 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 Corporation and HOVENSA produce and the Corporation
distributes fuel oils in the United States. Proposals by state
regulatory agencies and legislatures have been made that would
require a lower sulfur content of fuel oils. If adopted, these
proposals could require capital expenditures by the Corporation
and HOVENSA to meet the required sulfur content standards.
As described in Item 3, Legal Proceedings, in 2003 the
Corporation and HOVENSA began discussions with the U.S. EPA
regarding the EPA’s 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 90% of the
domestic refining capacity. Negotiations with the EPA are
continuing and substantial progress has been made toward
resolving this matter for both the Corporation and HOVENSA.
While the effect on the Corporation of the Petroleum Refining
Initiative cannot be estimated until a final settlement is
reached and entered by a court, additional significant future
capital expenditures and operating expenses will likely be
incurred by HOVENSA over a number of years. The amount of
penalties, if any, is not expected to be material.
The Corporation has undertaken a program to assess, monitor and
reduce the emission of greenhouse gases, including carbon
dioxide and methane. The Corporation recognizes that climate
change is a global environmental concern. The Corporation is
committed to the responsible management of greenhouse gas
emissions from our existing assets and future developments and
is implementing a strategy to control our carbon emissions.
The Corporation will have continuing expenditures for
environmental assessment and remediation. 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.
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Table of Contents
The Corporation accrues for environmental assessment and
remediation expenditures for known sites when the future costs
are probable and reasonably estimable. At year-end 2009, the
Corporation’s reserve for estimated environmental
liabilities was approximately $55 million. The
Corporation’s environmental assessment and remediation
expenditures were approximately $11 million in each of the
years 2009, 2008 and 2007. The Corporation expects that existing
reserves for environmental liabilities are sufficient for costs
to assess and remediate known sites. The Corporation anticipates
capital expenditures for facilities, primarily to comply with
federal, state and local environmental standards, of
approximately $50 million in 2010.
Forward-Looking
Information
Certain sections of Management’s Discussion and Analysis of
Financial Condition and Results of Operations and Quantitative
and Qualitative Disclosures about Market Risk, including
references to the Corporation’s 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 Corporation’s 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.
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
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. The
Corporation also has trading operations, principally through a
50% voting interest in a consolidated partnership that trades
energy commodities and energy derivatives. 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
Corporation’s senior management has approved. Controls
include volumetric, term and
value-at-risk
limits. The chief risk officer must approve the use of new
instruments or commodities. Risk limits are monitored and
reported on daily to business units and to senior management.
The Corporation’s risk management department also performs
independent verifications of sources of fair values and
validations of valuation models. These controls apply to all of
the Corporation’s risk management and trading activities,
including the consolidated trading partnership. The
Corporation’s treasury department is responsible for
administering foreign exchange rate and interest rate hedging
programs.
The Corporation uses
value-at-risk
to monitor and control commodity risk within its trading and
risk management 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. Results may vary from time to time as
strategies change in trading activities or hedging levels change
in risk management activities.
Instruments:
The Corporation primarily
uses forward commodity contracts, foreign exchange forward
contracts, futures, swaps, options and energy commodity based
securities in its risk management and trading activities. These
contracts are generally widely traded instruments with
standardized terms. The following describes these instruments
and how the Corporation uses them:
| • | 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 deemed normal purchase and sale contracts are excluded from the quantitative market risk disclosures. | |
| • | Forward Foreign Exchange Contracts: The Corporation enters into forward contracts primarily for the British pound, the Euro, and the Thai Baht, which commit the Corporation to buy or sell a fixed amount of these currencies at a predetermined exchange rate on a future date. |
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Table of Contents
| • | 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. | |
| • | 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. | |
| • | 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. | |
| • | Energy Securities: Energy securities include energy related equity or debt securities issued by a company or government or related derivatives on these securities. |
Risk
Management Activities
Energy marketing activities:
In its
energy marketing activities, the Corporation sells refined
petroleum products, natural gas and electricity principally to
commercial and industrial businesses at fixed and floating
prices for varying periods of time. Commodity contracts such as
futures, forwards, swaps and options together with physical
assets, such as storage, are used to obtain supply and reduce
margin volatility or lower costs related to sales contracts with
customers.
Corporate risk management:
Corporate
risk management activities include transactions designed to
reduce risk in the selling prices of crude oil or natural gas
produced by the Corporation or to reduce exposure to foreign
currency or interest rate movements. Generally, futures, swaps
or option strategies may be used to reduce risk in the selling
price of a portion of the Corporation’s crude oil or
natural gas production. Forward contracts may also be used to
purchase certain currencies in which the Corporation does
business with the intent of reducing exposure to foreign
currency fluctuations. Interest rate swaps may also be used,
generally to convert fixed rate interest payments to floating.
The Corporation uses foreign exchange contracts to reduce its
exposure to fluctuating foreign exchange rates by entering into
formal contracts for various currencies including the British
pound, the Euro and the Thai baht. At December 31, 2009 the
Corporation had a payable of $16 million related to foreign
exchange contracts maturing in 2010. The fair value of the
foreign exchange contracts was also a payable of
$16 million at December 31, 2009. The change in fair
value of the foreign exchange contracts from a 20% strengthening
of the US dollar exchange rate is estimated to be approximately
$172 million at December 31, 2009.
The Corporation’s debt of $4,467 million has a fair
value of $5,073 million at December 31, 2009. A 15%
decrease in the rate of interest would increase the fair value
of debt by approximately $120 million at December 31,
2009.
Value
at risk
Following is the value at risk for the Corporation’s energy
marketing and risk management activities:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
At December 31
|
$ | 8 | $ | 13 | ||||
|
Average
|
10 | 90 | ||||||
|
High
|
13 | 140 | ||||||
|
Low
|
8 | 13 | ||||||
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Table of Contents
Trading
Activities
Trading activities are conducted principally through a trading
partnership in which the Corporation has a 50% voting interest.
This consolidated entity intends to generate earnings through
various strategies primarily using energy commodities,
securities and derivatives. The Corporation also takes trading
positions for its own account.
Following is the value at risk for the Corporation’s
trading activities:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
At December 31
|
$ | 9 | $ | 17 | ||||
|
Average
|
12 | 13 | ||||||
|
High
|
15 | 17 | ||||||
|
Low
|
9 | 11 | ||||||
Derivative trading transactions are
marked-to-market
and unrealized gains or losses are reflected in income
currently. Gains or losses from sales of physical products are
recorded at the time of sale. Total realized gains (losses) on
trading activities amounted to $642 million in 2009 and
$(317) million in 2008. 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.
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Fair value of contracts outstanding at the beginning of the year
|
$ | 864 | $ | 154 | ||||
|
Change in fair value of contracts outstanding at the beginning
of the year and still outstanding at the end of the year
|
(6 | ) | (257 | ) | ||||
|
Reversal of fair value for contracts closed during the year
|
(534 | ) | 42 | |||||
|
Fair value of contracts entered into during the year and still
outstanding
|
(214 | ) | 925 | |||||
|
Fair value of contracts outstanding at the end of the year
|
$ | 110 | $ | 864 | ||||
The following table summarizes the sources of fair values of
derivatives used in the Corporation’s trading activities at
December 31, 2009:
|
2013 and
|
||||||||||||||||||||
| Total | 2010 | 2011 | 2012 | Beyond | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
Source of fair value
|
||||||||||||||||||||
|
Level 1
|
$ | (86 | ) | $ | (97 | ) | $ | 7 | $ | 2 | $ | 2 | ||||||||
|
Level 2
|
147 | 103 | 59 | (13 | ) | (2 | ) | |||||||||||||
|
Level 3
|
49 | 35 | 17 | 8 | (11 | ) | ||||||||||||||
|
Total
|
$ | 110 | $ | 41 | $ | 83 | $ | (3 | ) | $ | (11 | ) | ||||||||
The following table summarizes the receivables net of cash
margin and letters of credit relating to the Corporation’s
trading activities and the credit ratings of counterparties at
December 31:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Investment grade determined by outside sources
|
$ | 232 | $ | 263 | ||||
|
Investment grade determined internally*
|
120 | 133 | ||||||
|
Less than investment grade
|
61 | 58 | ||||||
|
Fair value of net receivables outstanding at the end of the year
|
$ | 413 | $ | 454 | ||||
| * | Based on information provided by counterparties and other available sources. |
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Table of Contents
| Item 8. | Financial Statements and Supplementary Data |
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
|
Page
|
||||
| Number | ||||
| 40 | ||||
| 41 | ||||
| 43 | ||||
| 44 | ||||
| 45 | ||||
| 46 | ||||
| 47 | ||||
| 77 | ||||
| 85 | ||||
| 91 | ||||
| * | 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. |
39
Table of Contents
Management’s
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, 2009.
The Corporation’s independent registered public accounting
firm, Ernst & Young LLP, has audited the effectiveness
of the Corporation’s internal control over financial
reporting as of December 31, 2009, as stated in their
report, which is included herein.
|
By
|
/s/ John
P. Rielly
|
By |
/s/ John
B. Hess
|
|||
| John P. Rielly | John B. Hess | |||||
| Senior Vice President and | Chairman of the Board and | |||||
| Chief Financial Officer | Chief Executive Officer |
February 26, 2010
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Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
We have audited Hess Corporation’s internal control over
financial reporting as of December 31, 2009, based on
criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (the COSO criteria). Hess
Corporation’s management is responsible for maintaining
effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over
financial reporting included in the accompanying
Management’s Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the
Corporation’s internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Hess Corporation maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2009 based on the COSO criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheet of Hess Corporation and consolidated
subsidiaries as of December 31, 2009 and 2008, and the
related statements of consolidated income, cash flows, and
equity and comprehensive income of Hess Corporation and
consolidated subsidiaries for each of the three years in the
period ended December 31, 2009, and our report dated
February 26, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young, LLP
February 26, 2010
New York, New York
41
Table of Contents
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 (the
“Corporation”) as of December 31, 2009 and 2008,
and the related statements of consolidated income, cash flows,
and equity and comprehensive income for each of the three years
in the period ended December 31, 2009. 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 Corporation’s 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, 2009 and 2008, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2009, in conformity with U.S. generally
accepted accounting principles. 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 new oil and gas reserve
estimation and disclosure requirements effective
December 31, 2009. Also, as discussed in Note 1 to the
consolidated financial statements, the Corporation adopted the
guidance originally issued in Financial Accounting Standards
Board (“FASB”) Financial Accounting Standard 160,
Noncontrolling Interests in Consolidated Financial Statements
(codified in FASB Accounting Standards Codification Topic
810,
Consolidation
), effective January 1, 2009.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), Hess
Corporation’s internal control over financial reporting as
of December 31, 2009, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission and our
report dated February 26, 2010 expressed an unqualified
opinion thereon.
/s/ Ernst & Young, LLP
February 26, 2010
New York, New York
42
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions of dollars; thousands of shares) | ||||||||
|
ASSETS
|
||||||||
|
CURRENT ASSETS
|
||||||||
|
Cash and cash equivalents
|
$ | 1,362 | $ | 908 | ||||
|
Accounts receivable
|
||||||||
|
Trade
|
3,650 | 4,059 | ||||||
|
Other
|
274 | 238 | ||||||
|
Inventories
|
1,438 | 1,308 | ||||||
|
Other current assets
|
1,263 | 819 | ||||||
|
Total current assets
|
7,987 | 7,332 | ||||||
|
INVESTMENTS IN AFFILIATES
|
||||||||
|
HOVENSA L.L.C.
|
681 | 919 | ||||||
|
Other
|
232 | 208 | ||||||
|
Total investments in affiliates
|
913 | 1,127 | ||||||
|
PROPERTY, PLANT AND EQUIPMENT
|
||||||||
|
Total — at cost
|
29,871 | 27,437 | ||||||
|
Less reserves for depreciation, depletion, amortization and
lease impairment
|
13,244 | 11,166 | ||||||
|
Property, plant and equipment — net
|
16,627 | 16,271 | ||||||
|
GOODWILL
|
1,225 | 1,225 | ||||||
|
DEFERRED INCOME TAXES
|
2,409 | 2,292 | ||||||
|
OTHER ASSETS
|
304 | 342 | ||||||
|
TOTAL ASSETS
|
$ | 29,465 | $ | 28,589 | ||||
| LIABILITIES AND EQUITY | ||||||||
|
CURRENT LIABILITIES
|
||||||||
|
Accounts payable
|
$ | 4,223 | $ | 5,045 | ||||
|
Accrued liabilities
|
1,954 | 1,905 | ||||||
|
Taxes payable
|
525 | 637 | ||||||
|
Current maturities of long-term debt
|
148 | 143 | ||||||
|
Total current liabilities
|
6,850 | 7,730 | ||||||
|
LONG-TERM DEBT
|
4,319 | 3,812 | ||||||
|
DEFERRED INCOME TAXES
|
2,222 | 2,241 | ||||||
|
ASSET RETIREMENT OBLIGATIONS
|
1,234 | 1,164 | ||||||
|
OTHER LIABILITIES AND DEFERRED CREDITS
|
1,312 | 1,251 | ||||||
|
Total liabilities
|
15,937 | 16,198 | ||||||
|
EQUITY
|
||||||||
|
Common stock, par value $1.00
|
||||||||
|
Authorized: 600,000 shares
|
||||||||
|
Issued: 2009 — 327,229 shares; 2008 —
326,133 shares
|
327 | 326 | ||||||
|
Capital in excess of par value
|
2,481 | 2,347 | ||||||
|
Retained earnings
|
12,251 | 11,642 | ||||||
|
Accumulated other comprehensive income (loss)
|
(1,675 | ) | (2,008 | ) | ||||
|
Total Hess Corporation stockholders’ equity
|
13,384 | 12,307 | ||||||
|
Noncontrolling interests
|
144 | 84 | ||||||
|
Total equity
|
13,528 | 12,391 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 29,465 | $ | 28,589 | ||||
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.
43
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars, except per share data) | ||||||||||||
|
REVENUES AND NON-OPERATING INCOME
|
||||||||||||
|
Sales (excluding excise taxes) and other operating revenues
|
$ | 29,614 | $ | 41,134 | $ | 31,727 | ||||||
|
Equity in income (loss) of HOVENSA L.L.C.
|
(229 | ) | 44 | 176 | ||||||||
|
Gain on asset sales
|
— | — | 21 | |||||||||
|
Other, net
|
184 | (115 | ) | 80 | ||||||||
|
Total revenues and non-operating income
|
29,569 | 41,063 | 32,004 | |||||||||
|
COSTS AND EXPENSES
|
||||||||||||
|
Cost of products sold (excluding items shown separately below)
|
20,961 | 29,567 | 22,532 | |||||||||
|
Production expenses
|
1,805 | 1,872 | 1,581 | |||||||||
|
Marketing expenses
|
1,008 | 1,025 | 944 | |||||||||
|
Exploration expenses, including dry holes and lease impairment
|
829 | 725 | 515 | |||||||||
|
Other operating expenses
|
183 | 209 | 161 | |||||||||
|
General and administrative expenses
|
647 | 672 | 614 | |||||||||
|
Interest expense
|
360 | 267 | 256 | |||||||||
|
Depreciation, depletion and amortization
|
2,254 | 2,029 | 1,576 | |||||||||
|
Total costs and expenses
|
28,047 | 36,366 | 28,179 | |||||||||
|
INCOME BEFORE INCOME TAXES
|
1,522 | 4,697 | 3,825 | |||||||||
|
Provision for income taxes
|
715 | 2,340 | 1,872 | |||||||||
|
NET INCOME
|
$ | 807 | $ | 2,357 | $ | 1,953 | ||||||
|
Less: Net income (loss) attributable to noncontrolling interests
|
67 | (3 | ) | 121 | ||||||||
|
NET INCOME ATTRIBUTABLE TO HESS CORPORATION
|
$ | 740 | $ | 2,360 | $ | 1,832 | ||||||
|
BASIC NET INCOME PER SHARE
|
$ | 2.28 | $ | 7.35 | $ | 5.86 | ||||||
|
DILUTED NET INCOME PER SHARE
|
$ | 2.27 | $ | 7.24 | $ | 5.74 | ||||||
|
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
(DILUTED)
|
326.0 | 325.8 | 319.3 | |||||||||
See accompanying notes to consolidated financial statements.
44
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net income
|
$ | 807 | $ | 2,357 | $ | 1,953 | ||||||
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
||||||||||||
|
Depreciation, depletion and amortization
|
2,254 | 2,029 | 1,576 | |||||||||
|
Exploratory dry hole costs
|
267 | 210 | 65 | |||||||||
|
Lease impairment
|
231 | 125 | 102 | |||||||||
|
Pre-tax gain on asset sales
|
— | — | (21 | ) | ||||||||
|
Benefit for deferred income taxes
|
(438 | ) | (57 | ) | (33 | ) | ||||||
|
Distributed earnings of HOVENSA L.L.C., net
|
229 | 6 | 124 | |||||||||
|
Stock compensation expense
|
128 | 119 | 87 | |||||||||
|
Changes in other operating assets and liabilities:
|
||||||||||||
|
(Increase) decrease in accounts receivable
|
320 | 357 | (783 | ) | ||||||||
|
Increase in inventories
|
(137 | ) | (56 | ) | (254 | ) | ||||||
|
Increase (decrease) in accounts payable and accrued liabilities
|
(542 | ) | (252 | ) | 597 | |||||||
|
Increase (decrease) in taxes payable
|
(81 | ) | 61 | 134 | ||||||||
|
Changes in other assets and liabilities
|
8 | (211 | ) | 80 | ||||||||
|
Net cash provided by operating activities
|
3,046 | 4,688 | 3,627 | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Capital expenditures
|
(2,918 | ) | (4,438 | ) | (3,578 | ) | ||||||
|
Proceeds from asset sales
|
— | — | 93 | |||||||||
|
Payments received on notes receivable
|
15 | 61 | 61 | |||||||||
|
Other, net
|
(21 | ) | (67 | ) | (50 | ) | ||||||
|
Net cash used in investing activities
|
(2,924 | ) | (4,444 | ) | (3,474 | ) | ||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Net (repayments) borrowings of debt with maturities of
90 days or less
|
(850 | ) | 30 | 202 | ||||||||
|
Debt with maturities of greater than 90 days
|
||||||||||||
|
Borrowings
|
1,991 | — | 32 | |||||||||
|
Repayments
|
(694 | ) | (62 | ) | (26 | ) | ||||||
|
Cash dividends paid
|
(131 | ) | (130 | ) | (127 | ) | ||||||
|
Payments to noncontrolling interests, net
|
(2 | ) | (121 | ) | (121 | ) | ||||||
|
Employee stock options exercised, including income tax benefits
|
18 | 340 | 111 | |||||||||
|
Net cash provided by (used in) financing activities
|
332 | 57 | 71 | |||||||||
|
NET INCREASE IN CASH AND CASH EQUIVALENTS
|
454 | 301 | 224 | |||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
908 | 607 | 383 | |||||||||
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$ | 1,362 | $ | 908 | $ | 607 | ||||||
See accompanying notes to consolidated financial statements.
45
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
|
Accumulated
|
||||||||||||||||||||||||||||
|
Capital in
|
Other
|
Total Hess
|
||||||||||||||||||||||||||
|
Common
|
Excess
|
Retained
|
Comprehensive
|
Stockholders’
|
Noncontrolling
|
Total
|
||||||||||||||||||||||
| Stock | of Par | Earnings | Income (Loss) | Equity | Interests | Equity | ||||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||||||
|
Balance at January 1, 2007
|
$ | 315 | $ | 1,689 | $ | 7,707 | $ | (1,564 | ) | $ | 8,147 | $ | 229 | $ | 8,376 | |||||||||||||
|
Net Income
|
1,832 | 1,832 | 121 | 1,953 | ||||||||||||||||||||||||
|
Deferred gains (losses) on cash flow hedges, after tax
|
||||||||||||||||||||||||||||
|
Effect of hedge losses recognized in income
|
325 | 325 | — | 325 | ||||||||||||||||||||||||
|
Net change in fair value of cash flow hedges
|
(659 | ) | (659 | ) | — | (659 | ) | |||||||||||||||||||||
|
Change in post retirement plan liabilities, after tax
|
17 | 17 | — | 17 | ||||||||||||||||||||||||
|
Change in foreign currency translation adjustment and other
|
40 | 40 | (3 | ) | 37 | |||||||||||||||||||||||
|
Total Comprehensive Income
|
1,555 | 118 | 1,673 | |||||||||||||||||||||||||
|
Activity related to restricted common stock awards, net
|
1 | 50 | — | — | 51 | — | 51 | |||||||||||||||||||||
|
Employee stock options, including income tax benefits
|
5 | 143 | — | — | 148 | — | 148 | |||||||||||||||||||||
|
Cash dividends declared
|
— | — | (127 | ) | — | (127 | ) | — | (127 | ) | ||||||||||||||||||
|
Payments to noncontrolling interests, net
|
— | — | — | — | — | (121 | ) | (121 | ) | |||||||||||||||||||
|
Balance at December 31, 2007
|
321 | 1,882 | 9,412 | (1,841 | ) | 9,774 | 226 | 10,000 | ||||||||||||||||||||
|
Net Income
|
2,360 | 2,360 | (3 | ) | 2,357 | |||||||||||||||||||||||
|
Deferred gain (losses) on cash flow hedges, after tax
|
||||||||||||||||||||||||||||
|
Effect of hedge losses recognized in income
|
311 | 311 | — | 311 | ||||||||||||||||||||||||
|
Net change in fair value of cash flow hedges
|
(310 | ) | (310 | ) | — | (310 | ) | |||||||||||||||||||||
|
Effect of adoption of fair value measurements accounting
standards
|
193 | 193 | — | 193 | ||||||||||||||||||||||||
|
Change in post retirement plan liabilities, after tax
|
(241 | ) | (241 | ) | — | (241 | ) | |||||||||||||||||||||
|
Change in foreign currency translation adjustment and other
|
(120 | ) | (120 | ) | (18 | ) | (138 | ) | ||||||||||||||||||||
|
Total Comprehensive Income
|
2,193 | (21 | ) | 2,172 | ||||||||||||||||||||||||
|
Activity related to restricted common stock awards, net
|
1 | 145 | — | — | 146 | — | 146 | |||||||||||||||||||||
|
Employee stock options, including income tax benefits
|
4 | 320 | — | — | 324 | — | 324 | |||||||||||||||||||||
|
Cash dividends declared
|
— | — | (130 | ) | — | (130 | ) | — | (130 | ) | ||||||||||||||||||
|
Payments to noncontrolling interests, net
|
— | — | — | — | — | (121 | ) | (121 | ) | |||||||||||||||||||
|
Balance at December 31, 2008
|
326 | 2,347 | 11,642 | (2,008 | ) | 12,307 | 84 | 12,391 | ||||||||||||||||||||
|
Net Income
|
740 | 740 | 67 | 807 | ||||||||||||||||||||||||
|
Deferred gains (losses) on cash flow hedges, after tax
|
||||||||||||||||||||||||||||
|
Effect of hedge losses recognized in income
|
963 | 963 | — | 963 | ||||||||||||||||||||||||
|
Net change in fair value of cash flow hedges
|
(729 | ) | (729 | ) | — | (729 | ) | |||||||||||||||||||||
|
Change in post retirement plan liabilities, after tax
|
(6 | ) | (6 | ) | — | (6 | ) | |||||||||||||||||||||
|
Change in foreign currency translation adjustment and other
|
105 | 105 | (5 | ) | 100 | |||||||||||||||||||||||
|
Total Comprehensive Income
|
1,073 | 62 | 1,135 | |||||||||||||||||||||||||
|
Activity related to restricted common stock awards, net
|
1 | 61 | — | — | 62 | — | 62 | |||||||||||||||||||||
|
Employee stock options, including income tax benefits
|
— | 73 | — | — | 73 | — | 73 | |||||||||||||||||||||
|
Cash dividends declared
|
— | — | (131 | ) | — | (131 | ) | — | (131 | ) | ||||||||||||||||||
|
Payments to noncontrolling interests, net
|
— | — | — | — | — | (2 | ) | (2 | ) | |||||||||||||||||||
|
Balance at December 31, 2009
|
$ | 327 | $ | 2,481 | $ | 12,251 | $ | (1,675 | ) | $ | 13,384 | $ | 144 | $ | 13,528 | |||||||||||||
See accompanying notes to consolidated financial statements.
46
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| 1. | Summary of Significant Accounting Policies |
Nature of Business:
Hess Corporation
and its 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,
Colombia, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana,
Indonesia, Libya, Malaysia, Norway, Peru, Russia, Thailand, the
United Kingdom and the United States. In addition, the
Corporation manufactures, purchases, transports, markets and
trades, 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. In
the preparation of these financial statements, the Corporation
has evaluated subsequent events through the date the financial
statements are issued.
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 Corporation’s 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
Corporation’s 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 Statement of Consolidated Income. The Corporation
recognizes revenues from the production of natural gas
properties based on sales to customers. Differences between
E&P natural gas volumes sold and the Corporation’s
share of natural gas production are not material. Revenues from
natural gas and electricity sales by the Corporation’s
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 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 Statement of Consolidated
Income.
Derivatives:
The Corporation utilizes
derivative instruments for both risk management and trading
activities. In risk management 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, as
well as changes in interest and 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
Corporation’s balance sheet. The Corporation’s 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 are
recognized currently in earnings.
47
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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.
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. 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.
Provisions for impairment of undeveloped oil and gas leases are
based on periodic evaluations and other factors. 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.
The Corporation records the cost of acquired customers in its
energy marketing activities as intangible assets and amortizes
these costs on the straight-line method over the expected
renewal period based on historical experience.
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
recognizes a liability 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
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.
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Impairment of Long-Lived Assets:
The
Corporation reviews long-lived assets 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 management’s
best estimate of future prices, which is determined with
reference to recent historical prices and published forward
prices, applied to projected production volumes and discounted
at a risk-adjusted rate. 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 average 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:
Goodwill is
tested for impairment annually in the fourth quarter or when
events or changes in circumstances indicate that the carrying
amount of the goodwill may not be recoverable. This impairment
test is calculated at the reporting unit level, which for the
Corporation’s goodwill is the Exploration and Production
operating segment. 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.
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. 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 expected to be realized. In addition, 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. Additionally, the Corporation has income taxes
which have been deferred on intercompany transactions eliminated
in consolidation related to transfers of property, plant and
equipment remaining within the consolidated group. The
amortization of these income taxes deferred on intercompany
transactions will occur ratably with the recovery through
depletion and depreciation of the carrying value of these
assets. The Corporation does not provide for deferred
U.S. income taxes for that portion of 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.
Fair Value Measurements:
The
Corporation adopted a new accounting standard for fair value
measurements, effective January 1, 2008 (ASC
820 — Fair Value Measurements and Disclosures,
originally issued as FAS 157,
Fair Value
Measurements
). The standard establishes a hierarchy for the
inputs used to measure fair value based on the source of the
input, which generally range from quoted prices for identical
instruments in a principal trading market (Level 1) to
estimates determined using related market data (Level 3).
Multiple inputs may be used to measure fair value, however, the
level of fair value for each financial asset or liability is
based on the lowest significant input level within this fair
value hierarchy.
Fair value measurements based on Level 1
inputs:
Measurements that are most observable
are based on quoted prices of identical instruments obtained
from the principal markets in which they are traded. Closing
prices are both readily available and representative of fair
value. Market transactions occur with sufficient
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
frequency and volume to assure liquidity. The fair value of
certain of the Corporation’s exchange traded futures and
options are considered Level 1.
Fair value measurements based on Level 2
inputs:
Measurements derived indirectly from
observable inputs or from quoted prices from markets that are
less liquid are considered Level 2. Measurements based on
Level 2 inputs include
over-the-counter
derivative instruments that are priced on an exchange traded
curve, but have contractual terms that are not identical to
exchange traded contracts. The Corporation utilizes fair value
measurements based on Level 2 inputs for certain forwards,
swaps and options. The liability related to the
Corporation’s crude oil hedges is classified as
Level 2.
Fair value measurements based on Level 3
inputs:
Measurements that are least
observable are estimated from related market data, determined
from sources with little or no market activity for comparable
contracts or are positions with longer durations. For example,
in its energy marketing business, the Corporation sells natural
gas and electricity to customers and offsets the price exposure
by purchasing forward contracts. The fair value of these sales
and purchases may be based on specific prices at less liquid
delivered locations, which are classified as Level 3. There
may be offsets to these positions that are priced based on more
liquid markets, which are, therefore, classified as Level 1
or Level 2.
The impact of adopting the fair value measurements standard was
not material to the Corporation’s results of operations.
Upon adoption in 2008, the Corporation recorded a reduction in
the net deferred hedge losses reflected in Accumulated other
comprehensive income, which increased equity by
$193 million, after income taxes.
Effective December 31, 2008, the Corporation applied the
provisions of a new accounting standard for the accounting for
liabilities measured at fair value with a third-party credit
enhancement (ASC 820 — Fair Value Measurements and
Disclosures, originally issued as Emerging Issues Task Force
08-5,
Issuer’s Accounting for Liabilities Measured at Fair
Value with a Third-Party Credit Enhancement
). Upon adoption,
the Corporation revalued certain derivative liabilities
collateralized by letters of credit to reflect the
Corporation’s credit rating rather than the credit rating
of the issuing bank. The adoption resulted in an increase in
Sales and other operating revenues of approximately
$13 million and an increase in Accumulated other
comprehensive income of approximately $78 million, with a
corresponding decrease in derivative liabilities recorded within
Accounts payable.
Retirement Plans:
The Corporation
recognizes the underfunded status of defined benefit
postretirement plans on the balance sheet. For the
Corporation’s pension plans, the underfunded status is
measured as the difference between the fair value of plan assets
and the projected benefit obligation. The Corporation recognizes
the net changes in the funded status of these plans in the year
in which such changes occur.
Share-Based Compensation:
The fair
value of all share-based compensation is expensed and recognized
on a straight-line basis over the vesting period of the awards.
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 non-functional currency
into the functional currency are recorded in Other, net within
Sales and other operating revenues in the Statement of
Consolidated 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 equity titled Accumulated other comprehensive
income (loss).
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.
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
50
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Corporation capitalizes environmental expenditures that increase
the life or efficiency of property or that reduce or prevent
future adverse impacts to the environment.
Changes in Accounting Policies:
The
Financial Accounting Standards Board (FASB) Accounting Standards
Codification (ASC) became effective on July 1, 2009. The
ASC combined multiple sources of authoritative accounting
literature into a single source of authoritative GAAP organized
by accounting topic. Since the ASC was not intended to change
existing GAAP, the only impact on the Corporation’s
financial statements was that specific references to accounting
principles have been changed to refer to the ASC.
Effective January 1, 2009, the Corporation adopted the FASB
accounting standard for the accounting for and reporting of
noncontrolling interests in a consolidated subsidiary (ASC
810 — Consolidation, originally issued as
FAS 160,
Noncontrolling Interests in Consolidated
Financial Statements, an amendment of ARB No. 51
). As
required, the Corporation retrospectively applied the
presentation and disclosure requirements of this standard. At
December 31, 2009 and December 31, 2008,
noncontrolling interests of $144 million and
$84 million, respectively, have been classified as a
component of equity. Prior to adoption, noncontrolling interests
were classified in Other liabilities. Net income (loss)
attributable to the noncontrolling interests must also be
separately reported in the Statement of Consolidated Income.
Certain other amounts in the consolidated financial statements
and footnotes have been reclassified to conform with the
presentation requirements of this standard.
Effective January 1, 2009, the Corporation adopted the FASB
accounting standard that expanded the qualitative, quantitative
and credit risk disclosure requirements related to an
entity’s use of derivative instruments (ASC 815 —
Derivatives and Hedging, originally issued as FAS 161,
Disclosures about Derivative Instruments and Hedging
Activities
). See Note 14, Risk Management and Trading
Activities, for these disclosures.
Effective January 1, 2009, the Corporation also adopted the
FASB staff position that requires the application of the fair
value measurement and disclosure provisions to nonfinancial
assets and liabilities that are measured at fair value on a
nonrecurring basis (ASC 820 — Fair Value Measurements
and Disclosures, originally issued as FASB Staff Position
No. 157-2,
Effective Date of FASB Statement No. 157
). Such fair
value measurements are determined based on the same fair value
hierarchy of inputs required to measure the fair value of
financial assets and liabilities. The impact of this accounting
standard was not material to the Corporation’s consolidated
financial statements.
Effective June 30, 2009, the Corporation adopted the FASB
accounting standard which provides guidance on the accounting
for and disclosure of events that occur after the balance sheet
date but before financial statements are issued (ASC
855 — Subsequent Events, originally issued as
FAS 165,
Subsequent Events
). The adoption of this
standard did not impact the Corporation’s existing practice
of evaluating subsequent events through the date the financial
statements are issued.
In January 2010, the FASB adopted an accounting standards update
(ASU) Extractive Activities — Oil and Gas (ASC
932) Oil and Gas Reserve Estimation and Disclosures, which
is effective for year-end 2009 reporting and amends the
requirements for oil and gas reserve estimation and disclosures.
The objective of the ASU was to align accounting standards with
the previously issued Securities and Exchange Commission (SEC)
requirements on oil and gas reserve estimation and disclosure.
The main provisions of the ASU are to expand the definition of
oil and gas producing activities to include the extraction of
resources which are saleable as synthetic oil or gas, to change
the price assumption used for reserve estimation and future cash
flows to a twelve month average from the year-end price and to
amend the geographic disclosure requirements for reporting
reserves and other supplementary oil and gas data. See the
Supplementary Oil and Gas Data for these disclosures.
Recently Issued Accounting
Standards:
In June 2009, the FASB amended
existing accounting standards to eliminate the concept of a
qualifying special-purpose entity (ASC 860 — Transfers
and Servicing, originally issued as FAS 166,
Accounting
for Transfers of Financial Assets — an amendment of
FASB Statement No. 140
), which did not require
consolidation under existing GAAP. The FASB also amended
existing standards to limit the circumstances in which
transferred financial assets should be derecognized (and ASC
810 — Consolidation, originally issued as
FAS 167,
Amendments to FASB Interpretation
No. FIN 46(R)).
The amended standards require
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
additional analysis of variable interest entities to determine
if consolidation is necessary. The adoption of these standards
will not have a material impact on the Corporation’s
financial statements. As required, the Corporation will adopt
the provisions of these standards effective January 1, 2010.
| 2. | Acquisitions and Divestitures |
2009:
The Corporation acquired for
$74 million a 50% interest in Blocks PM301 and PM302 in
Malaysia, which are adjacent to Block
A-18
of the
Joint Development Area of Malaysia/Thailand (JDA) and contain an
extension of the Bumi Field. The Corporation also acquired 37
previously leased retail gasoline stations, primarily through
the assumption of $65 million of fixed rate notes.
2008:
The Corporation acquired the
remaining 22.5% interest in its Gabonese subsidiary for
$285 million, of which $210 million was allocated to
proved properties. The Corporation expanded its energy marketing
business by acquiring fuel oil, natural gas, and electricity
customer accounts, and a terminal and related assets, for an
aggregate of approximately $100 million.
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. This
transaction was accounted for as an asset acquisition. Genghis
Khan has been unitized with the Shenzi development.
The Corporation completed the sale of its interests in the Scott
and Telford fields located in the United Kingdom North Sea for
$93 million and recorded a gain of $21 million
($15 million after income taxes) that is included in Other,
net in the Statement of Consolidated Income.
| 3. | Inventories |
Inventories at December 31 are as follows:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Crude oil and other charge stocks
|
$ | 424 | $ | 383 | ||||
|
Refined products and natural gas
|
1,429 | 988 | ||||||
|
Less: LIFO adjustment
|
(815 | ) | (500 | ) | ||||
| 1,038 | 871 | |||||||
|
Merchandise, materials and supplies
|
400 | 437 | ||||||
|
Total
|
$ | 1,438 | $ | 1,308 | ||||
The percentage of LIFO inventory to total crude oil, refined
products and natural gas inventories was 64% and 60% at
December 31, 2009 and 2008, respectively. In 2009, the
Corporation recorded a pre-tax charge of $25 million
($18 million after income taxes) to write down materials
inventories in Equatorial Guinea and the United States, the
majority of which was recorded in Production expenses. During
2007, the Corporation reduced LIFO inventories, which are
carried at lower costs than current inventory costs. The effect
of the LIFO inventory liquidation was to decrease Cost of
products sold by approximately $38 million
($24 million after income taxes).
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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:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Summarized Balance Sheet, at December 31
|
||||||||||||
|
Cash and cash equivalents
|
$ | 78 | $ | 75 | $ | 279 | ||||||
|
Other current assets
|
580 | 664 | 1,183 | |||||||||
|
Net fixed assets
|
2,080 | 2,136 | 2,181 | |||||||||
|
Other assets
|
33 | 58 | 62 | |||||||||
|
Current liabilities
|
(953 | ) | (679 | ) | (1,459 | ) | ||||||
|
Long-term debt
|
(356 | ) | (356 | ) | (356 | ) | ||||||
|
Deferred liabilities and credits
|
(137 | ) | (104 | ) | (75 | ) | ||||||
|
Members’ equity
|
$ | 1,325 | $ | 1,794 | $ | 1,815 | ||||||
|
Summarized Income Statement, for the years ended December 31
|
||||||||||||
|
Total revenues
|
$ | 10,085 | $ | 17,518 | $ | 13,439 | ||||||
|
Costs and expenses
|
(10,536 | ) | (17,423 | ) | (13,082 | ) | ||||||
|
Net income (loss)
|
$ | (451 | ) | $ | 95 | $ | 357 | |||||
|
Hess Corporation’s share*
|
$ | (229 | ) | $ | 44 | $ | 176 | |||||
|
Summarized Cash Flow Statement, for the years ended December 31
|
||||||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$ | 87 | $ | (20 | ) | $ | 654 | |||||
|
Investing activities
|
(84 | ) | (85 | ) | (165 | ) | ||||||
|
Financing activities
|
— | (99 | ) | (500 | ) | |||||||
|
Net increase (decrease) in cash and cash equivalents
|
$ | 3 | $ | (204 | ) | $ | (11 | ) | ||||
| * | Before Virgin Islands income taxes, which were recorded in the Corporation’s income tax provision. |
The Corporation received cash distributions from HOVENSA of
$50 million in 2008 and $300 million during 2007.
The Corporation guarantees the payment of up to 50% of the value
of HOVENSA’s crude oil purchases from certain suppliers
other than PDVSA. The guarantee amounted to $121 million at
December 31, 2009. 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
$15 million to the extent HOVENSA does not have funds to
meet its senior debt obligations.
53
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 5. | Property, Plant and Equipment |
Property, plant and equipment at December 31 consists of the
following:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Exploration and Production
|
||||||||
|
Unproved properties
|
$ | 2,347 | $ | 2,265 | ||||
|
Proved properties
|
3,121 | 3,009 | ||||||
|
Wells, equipment and related facilities
|
22,118 | 20,058 | ||||||
| 27,586 | 25,332 | |||||||
|
Marketing, Refining and Corporate
|
2,285 | 2,105 | ||||||
|
Total — at cost
|
29,871 | 27,437 | ||||||
|
Less: reserves for depreciation, depletion, amortization and
lease impairment
|
13,244 | 11,166 | ||||||
|
Property, plant and equipment — net
|
$ | 16,627 | $ | 16,271 | ||||
In December 2009, the Corporation agreed to a strategic exchange
of all of its interests in Gabon and the Clair Field in the
United Kingdom for additional interests in the Valhall and Hod
fields offshore Norway. The transaction, which has an effective
date of January 1, 2010, is subject to various regulatory
and other approvals. In addition, the partners are in
discussions regarding the applicability of pre-emption to this
transaction. In January 2010, the Corporation completed the sale
of its interest in the Jambi Merang Field in Indonesia. The
Corporation has classified its interests in Gabon, the Clair
Field and Jambi Merang Field as assets held for sale. At
December 31, 2009, the carrying amount of these assets
totaling $717 million were reported in Other current
assets, and asset retirement obligations and deferred income
taxes totaling $254 million were reported in Accrued
liabilities.
The Corporation recorded asset impairments totaling
$52 million ($26 million after income taxes) in 2009,
$30 million ($17 million after income taxes) in 2008,
and $112 million ($56 million after income taxes) in
2007. These impairments are 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:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Beginning balance at January 1
|
$ | 1,094 | $ | 608 | $ | 399 | ||||||
|
Additions to capitalized exploratory well costs pending the
determination of proved reserves
|
433 | 560 | 229 | |||||||||
|
Reclassifications to wells, facilities, and equipment based on
the determination of proved reserves
|
(16 | ) | (67 | ) | (20 | ) | ||||||
|
Capitalized exploratory well costs charged to expense
|
(74 | ) | (7 | ) | — | |||||||
|
Ending balance at December 31
|
$ | 1,437 | $ | 1,094 | $ | 608 | ||||||
|
Number of wells at end of year
|
53 | 45 | 30 | |||||||||
The preceding table excludes exploratory dry hole costs of
$193 million, $203 million and $65 million in
2009, 2008 and 2007, respectively, which were incurred and
subsequently expensed in the same year.
54
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At December 31, 2009, exploratory drilling costs
capitalized in excess of one year past completion of drilling
were as follows (in millions):
|
2008
|
$ | 468 | ||
|
2007
|
109 | |||
|
2006
|
215 | |||
|
2003 to 2005
|
56 | |||
| $ | 848 | |||
The capitalized well costs in excess of one year relate to 15
projects. Approximately 72% of the capitalized well costs in
excess of one year relate to the Pony and Tubular Bells projects
in the deepwater Gulf of Mexico where development planning is
underway. In addition, the Corporation plans to drill another
appraisal well at Pony in 2010. Approximately 12% of the costs
in excess of one year relate to Western Australia (WA-390-P)
where further drilling is planned in 2010. The remainder of the
costs relate to projects where further drilling is planned or
development planning and other assessment activities are ongoing
to determine the economic and operating viability of the
projects.
| 6. | Asset Retirement Obligations |
The following table describes changes to the Corporation’s
asset retirement obligations:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Asset retirement obligations at January 1
|
$ | 1,214 | $ | 1,055 | ||||
|
Liabilities incurred
|
14 | 35 | ||||||
|
Liabilities settled or disposed of
|
(58 | ) | (56 | ) | ||||
|
Accretion expense
|
72 | 67 | ||||||
|
Revisions
|
(23 | ) | 309 | |||||
|
Foreign currency translation
|
78 | (196 | ) | |||||
|
Asset retirement obligations at December 31
|
1,297 | 1,214 | ||||||
|
Less: current obligations
|
63 | 50 | ||||||
|
Long-term obligations at December 31
|
$ | 1,234 | $ | 1,164 | ||||
Revisions are primarily attributable to changes in service and
equipment costs in the oil and gas industry.
55
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 7. |
|
Long-term debt at December 31 consists of the following:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Revolving credit facility
|
$ | — | $ | 350 | ||||
|
Asset-backed credit facility
|
— | 500 | ||||||
|
Fixed rate debentures:
|
||||||||
|
7.4% due 2009
|
— | 104 | ||||||
|
6.7% due 2011
|
116 | 662 | ||||||
|
7.0% due 2014
|
250 | — | ||||||
|
8.1% due 2019
|
997 | — | ||||||
|
7.9% due 2029
|
694 | 694 | ||||||
|
7.3% due 2031
|
746 | 745 | ||||||
|
7.1% due 2033
|
598 | 598 | ||||||
|
6.0% due 2040
|
744 | — | ||||||
|
Total fixed rate debentures
|
4,145 | 2,803 | ||||||
|
Fixed rate notes, weighted average rate 8.5%, due through 2023
|
154 | 108 | ||||||
|
Project lease financing, weighted average rate 5.1%, due through
2014
|
113 | 132 | ||||||
|
Pollution control revenue bonds, weighted average rate 5.9%, due
through 2034
|
53 | 53 | ||||||
|
Other loans, weighted average rate 9.0%, due through 2019
|
2 | 9 | ||||||
| 4,467 | 3,955 | |||||||
|
Less: amount included in current maturities
|
148 | 143 | ||||||
|
Total
|
$ | 4,319 | $ | 3,812 | ||||
In February 2009, the Corporation issued $250 million of
5 year senior unsecured notes with a coupon of 7% and
$1 billion of 10 year senior unsecured notes with a
coupon of 8.125%. The majority of the proceeds were used to
repay debt under the revolving credit facility and outstanding
borrowings on other credit facilities. In December 2009, the
Corporation issued $750 million of 30 year bonds with
a coupon of 6% and tendered for the $662 million of bonds
due in August 2011. The Corporation completed the purchase of
$546 million of the 2011 bonds in December 2009. The
Corporation recorded a charge of $54 million related to the
repurchase in Other, net within the Statement of Consolidated
Income ($34 million after income taxes). The remaining
$116 million of the 2011 bonds, classified as Current
maturities of long term debt at December 31, 2009, was
redeemed in January 2010, resulting in a charge of approximately
$11 million ($7 million after income taxes).
The aggregate long-term debt maturing during the next five years
is as follows (in millions): 2010 — $148 (included in
current liabilities); 2011 — $32; 2012 —
$34; 2013 — $37 and 2014 — $333.
At December 31, 2009, the Corporation’s fixed rate
debentures have a principal amount of $4,166 million
($4,145 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, 2009, the Corporation has
available capacity on the facility of $3.0 billion. Current
borrowings under the facility bear interest at 0.4% above the
London Interbank Offered Rate and a facility fee of 0.1% per
annum is payable on the amount of the facility. The interest
rate and facility fee are subject to adjustment if the
Corporation’s credit rating changes.
The Corporation has a 364 day asset-backed credit facility
securitized by certain accounts receivable from its Marketing
and Refining operations. Under the terms of this financing
arrangement, the Corporation has the ability
56
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
to borrow or issue letters of credit of up to $1.0 billion
at December 31, 2009, subject to the availability of
sufficient levels of eligible receivables. At December 31,
2009, outstanding letters of credit under this facility were
collateralized by a total of $1,326 million of accounts
receivable, which are held by a wholly-owned subsidiary. These
receivables are only available to pay the general obligations of
the Corporation after satisfaction of the outstanding
obligations under the asset backed facility.
In 2009, the Corporation assumed an additional $65 million
in fixed rate notes in connection with the acquisition of 37
previously leased retail gasoline stations.
The Corporation’s long-term debt agreements contain a
financial covenant that restricts the amount of total borrowings
and secured debt. At December 31, 2009, the Corporation is
permitted to borrow up to an additional $18.1 billion for
the construction or acquisition of assets. The Corporation has
the ability to borrow up to an additional $3.7 billion of
secured debt at December 31, 2009.
Outstanding letters of credit at December 31 were as follows:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Revolving credit facility
|
$ | — | $ | 176 | ||||
|
Asset-backed credit facility
|
500 | — | ||||||
|
Committed lines*
|
1,155 | 1,973 | ||||||
|
Uncommitted short-term lines*
|
1,192 | 1,686 | ||||||
|
Total
|
$ | 2,847 | $ | 3,835 | ||||
| * | Committed and uncommitted lines have expiration dates primarily through 2010. |
Of the total letters of credit outstanding at December 31,
2009, $100 million relates to contingent liabilities and
the remaining $2,747 million primarily relates to
liabilities recorded on the balance sheet.
The total amount of interest paid (net of amounts capitalized)
was $335 million, $266 million and $257 million
in 2009, 2008 and 2007, respectively. The Corporation
capitalized interest of $6 million, $7 million and
$50 million in 2009, 2008, and 2007, respectively.
| 8. | Share-Based Compensation |
The Corporation awards restricted common stock and stock options
under its 2008 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 Income Taxes | After Income Taxes | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Stock options
|
$ | 58 | $ | 51 | $ | 36 | $ | 36 | $ | 31 | $ | 23 | ||||||||||||
|
Restricted stock
|
70 | 68 | 51 | 44 | 43 | 31 | ||||||||||||||||||
|
Total
|
$ | 128 | $ | 119 | $ | 87 | $ | 80 | $ | 74 | $ | 54 | ||||||||||||
Based on restricted stock and stock option awards outstanding at
December 31, 2009, unearned compensation expense, before
income taxes, will be recognized in future years as follows (in
millions): 2010 — $88, 2011 — $42 and
2012 — $4.
57
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The Corporation’s 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, 2007
|
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 | ||||||||||||
|
Granted
|
2,473 | 82.55 | 1,289 | 85.22 | ||||||||||||
|
Exercised
|
(3,852 | ) | 29.17 | — | — | |||||||||||
|
Vested
|
— | — | (2,787 | ) | 21.40 | |||||||||||
|
Forfeited
|
(213 | ) | 60.61 | (142 | ) | 58.60 | ||||||||||
|
Outstanding at December 31, 2008
|
9,700 | 52.73 | 3,161 | 64.78 | ||||||||||||
|
Granted
|
3,135 | 56.44 | 1,056 | 56.27 | ||||||||||||
|
Exercised
|
(416 | ) | 38.85 | — | — | |||||||||||
|
Vested
|
— | — | (893 | ) | 50.13 | |||||||||||
|
Forfeited
|
(317 | ) | 65.68 | (376 | ) | 66.11 | ||||||||||
|
Outstanding at December 31, 2009
|
12,102 | 53.83 | 2,948 | 66.00 | ||||||||||||
|
Exercisable at December 31, 2007
|
5,408 | $ | 27.34 | |||||||||||||
|
Exercisable at December 31, 2008
|
4,522 | 36.95 | ||||||||||||||
|
Exercisable at December 31, 2009
|
6,636 | 46.11 | ||||||||||||||
The table below summarizes information regarding the outstanding
and exercisable stock options as of December 31, 2009:
| Outstanding Options | Exercisable Options | |||||||||||||||||||
|
Weighted-
|
||||||||||||||||||||
|
Average
|
Weighted-
|
Weighted-
|
||||||||||||||||||
|
Remaining
|
Average
|
Average
|
||||||||||||||||||
|
Range of
|
Contractual
|
Exercise Price
|
Exercise Price
|
|||||||||||||||||
|
Exercise Prices
|
Options | Life | per Share | Options | per Share | |||||||||||||||
| (Thousands) | (Years) | (Thousands) | ||||||||||||||||||
|
$10.00 – $40.00
|
2,321 | 4 | $ | 26.04 | 2,321 | $ | 26.04 | |||||||||||||
|
$40.01 – $50.00
|
1,943 | 6 | 49.15 | 1,937 | 49.17 | |||||||||||||||
|
$50.01 – $55.00
|
2,325 | 7 | 53.19 | 1,479 | 53.20 | |||||||||||||||
|
$55.01 – $60.00
|
3,097 | 9 | 56.48 | 42 | 57.69 | |||||||||||||||
|
$60.01 – $120.00
|
2,416 | 8 | 81.50 | 857 | 80.78 | |||||||||||||||
| 12,102 | 7 | 53.83 | 6,636 | 46.11 | ||||||||||||||||
The intrinsic value (or the amount by which the market price of
the Corporation’s Common Stock exceeds the exercise price
of an option) for outstanding options and exercisable options at
December 31, 2009 was $132 million
58
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and $113 million, respectively. At December 31, 2009,
assuming forfeitures of 2% per year, 11,900,000 outstanding
options are expected to vest at a weighted average exercise
price of $53.70 per share. At December 31, 2009, the
weighted average remaining term of exercisable options was
6 years.
The Corporation uses the Black-Scholes model to estimate the
fair value of employee stock options. The following weighted
average assumptions were utilized for stock options awarded:
| 2009 | 2008 | 2007 | ||||||||||
|
Risk free interest rate
|
1.80 | % | 2.70 | % | 4.70 | % | ||||||
|
Stock price volatility
|
.390 | .294 | .316 | |||||||||
|
Dividend yield
|
.70 | % | .50 | % | .75 | % | ||||||
|
Expected term in years
|
4.5 | 5.0 | 5.0 | |||||||||
|
Weighted average fair value per option granted
|
$ | 18.47 | $ | 24.09 | $ | 18.07 | ||||||
The assumption above for the risk free interest rate is based on
the expected terms of the options and is obtained from published
sources. The stock price volatility is determined from
historical experience using the same period as the expected
terms of the options. The expected stock option term is based on
historical exercise patterns and the expected future holding
period.
In May 2008, shareholders approved the 2008 Long-Term Incentive
Plan. The Corporation also has stock options outstanding under a
former plan. At December 31, 2009, the number of common
shares reserved for issuance under the 2008 Long-Term Incentive
Plan is as follows (in thousands):
|
Total common shares reserved for issuance
|
10,844 | |||
|
Less: stock options outstanding
|
3,111 | |||
|
Available for future awards of restricted stock and stock options
|
7,733 | |||
| 9. | Foreign Currency Translation |
Foreign currency gains (losses) before income taxes amounted to
$20 million in 2009, $(212) million in 2008 and
$17 million in 2007. The foreign currency loss in 2008
reflects the net effect of significant exchange rate movements
in the fourth quarter of 2008 on the remeasurement of assets,
liabilities and foreign currency forward contracts by certain
foreign businesses. The balances in accumulated other
comprehensive income (loss) related to foreign currency
translation were reductions in stockholders’ equity of
$18 million at December 31, 2009 and $123 million
at December 31, 2008.
| 10. | Retirement Plans |
The Corporation has funded noncontributory defined benefit
pension plans for a significant portion of its employees. In
addition, the Corporation has an unfunded supplemental pension
plan covering certain employees. The unfunded supplemental
pension plan provides for incremental pension payments from the
Corporation so that total pension payments equal amounts that
would have been payable from the Corporation’s principal
pension plans, were it not for limitations imposed by income tax
regulations. The plans provide defined benefits based on years
of service and final average salary. Additionally, the
Corporation maintains an unfunded postretirement medical plan
that provides health benefits to certain qualified retirees from
ages 55 through 65. The measurement date for all retirement
plans is December 31.
59
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table summarizes the Corporation’s benefit
obligations and the fair value of plan assets and shows the
funded status of the pension and postretirement medical plans:
|
Funded
|
Unfunded
|
Postretirement
|
||||||||||||||||||||||
| Pension Plans | Pension Plan | Medical Plan | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Change in benefit obligation
|
||||||||||||||||||||||||
|
Balance at January 1
|
$ | 1,125 | $ | 1,136 | $ | 165 | $ | 147 | $ | 77 | $ | 86 | ||||||||||||
|
Service cost
|
34 | 36 | 6 | 6 | 3 | 3 | ||||||||||||||||||
|
Interest cost
|
72 | 71 | 11 | 9 | 4 | 4 | ||||||||||||||||||
|
Actuarial (gain) loss
|
139 | 19 | 43 | 11 | 3 | (13 | ) | |||||||||||||||||
|
Benefit payments
|
(43 | ) | (42 | ) | (2 | ) | (8 | ) | (3 | ) | (3 | ) | ||||||||||||
|
Plan settlement*
|
— | — | (35 | ) | — | — | — | |||||||||||||||||
|
Foreign currency exchange rate changes
|
32 | (95 | ) | — | — | — | — | |||||||||||||||||
|
Balance at December 31
|
1,359 | 1,125 | 188 | 165 | 84 | 77 | ||||||||||||||||||
|
Change in fair value of plan assets
|
||||||||||||||||||||||||
|
Balance at January 1
|
745 | 1,075 | — | — | — | — | ||||||||||||||||||
|
Actual return on plan assets
|
161 | (280 | ) | — | — | — | — | |||||||||||||||||
|
Employer contributions
|
183 | 70 | 37 | 8 | 3 | 3 | ||||||||||||||||||
|
Benefit payments
|
(43 | ) | (42 | ) | (37 | ) | (8 | ) | (3 | ) | (3 | ) | ||||||||||||
|
Foreign currency exchange rate changes
|
26 | (78 | ) | — | — | — | — | |||||||||||||||||
|
Balance at December 31
|
1,072 | 745 | — | — | — | — | ||||||||||||||||||
|
Funded status (plan assets less than benefit
obligations) at December 31
|
(287 | ) | (380 | ) | (188 | )** | (165 | )** | (84 | ) | (77 | ) | ||||||||||||
|
Unrecognized net actuarial losses
|
495 | 513 | 92 | 78 | 16 | 13 | ||||||||||||||||||
|
Net amount recognized
|
$ | 208 | $ | 133 | $ | (96 | ) | $ | (87 | ) | $ | (68 | ) | $ | (64 | ) | ||||||||
| * | The plan settlement relates to employee retirements during 2009. As a result, the Corporation recorded a charge of $17 million ($10 million after income taxes) for the impact of this settlement. | |
| ** | The trust established by the Corporation for the supplemental plan held assets valued at $40 million at December 31, 2009 and $65 million at December 31, 2008. |
Amounts recognized in the consolidated balance sheet at December
31 consist of the following:
|
Funded
|
Unfunded
|
Postretirement
|
||||||||||||||||||||||
| Pension Plans | Pension Plan | Medical Plan | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Accrued benefit liability
|
$ | (287 | ) | $ | (380 | ) | $ | (188 | ) | $ | (165 | ) | $ | (84 | ) | $ | (77 | ) | ||||||
|
Accumulated other comprehensive loss*
|
495 | 513 | 92 | 78 | 16 | 13 | ||||||||||||||||||
|
Net amount recognized
|
$ | 208 | $ | 133 | $ | (96 | ) | $ | (87 | ) | $ | (68 | ) | $ | (64 | ) | ||||||||
| * | The after-tax reduction to equity recorded in Accumulated other comprehensive income (loss) was $413 million at December 31, 2009 and $407 million at December 31, 2008. |
60
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The accumulated benefit obligation for the funded defined
benefit pension plans was $1,229 million at
December 31, 2009 and $1,032 million at
December 31, 2008. The accumulated benefit obligation for
the unfunded defined benefit pension plan was $172 million
at December 31, 2009 and $149 million at
December 31, 2008.
Components of net periodic benefit cost for funded and unfunded
pension plans and the postretirement medical plan consisted of
the following:
| Pension Plans | Postretirement Medical Plan | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Service cost
|
$ | 40 | $ | 42 | $ | 41 | $ | 3 | $ | 3 | $ | 3 | ||||||||||||
|
Interest cost
|
83 | 80 | 73 | 4 | 4 | 4 | ||||||||||||||||||
|
Expected return on plan assets
|
(59 | ) | (80 | ) | (74 | ) | — | — | — | |||||||||||||||
|
Amortization of unrecognized net actuarial loss
|
65 | 19 | 23 | — | — | (1 | ) | |||||||||||||||||
|
Settlement loss
|
17 | — | — | — | — | 2 | ||||||||||||||||||
|
Net periodic benefit cost
|
$ | 146 | $ | 61 | $ | 63 | $ | 7 | $ | 7 | $ | 8 | ||||||||||||
Prior service costs and actuarial gains and losses in excess of
10% of the greater of the benefit obligation or the market value
of assets are amortized over the average remaining service
period of active employees.
The Corporation’s 2010 pension and postretirement medical
expense is estimated to be approximately $110 million, of
which approximately $50 million relates to the amortization
of unrecognized net actuarial losses.
The weighted-average actuarial assumptions used by the
Corporation’s funded and unfunded pension plans were as
follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Weighted-average assumptions used to determine benefit
obligations at December 31
|
||||||||||||
|
Discount rate
|
5.8 | % | 6.3 | % | 6.3 | % | ||||||
|
Rate of compensation increase
|
4.3 | 4.4 | 4.4 | |||||||||
|
Weighted-average assumptions used to determine net benefit cost
for years ended December 31
|
||||||||||||
|
Discount rate
|
6.3 | 6.3 | 5.8 | |||||||||
|
Expected return on plan assets
|
7.5 | 7.5 | 7.5 | |||||||||
|
Rate of compensation increase
|
4.4 | 4.4 | 4.4 | |||||||||
The actuarial assumptions used by the Corporation’s
postretirement medical plan were as follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Assumptions used to determine benefit obligations at December 31
|
||||||||||||
|
Discount rate
|
5.4 | % | 6.3 | % | 6.3 | % | ||||||
|
Initial health care trend rate
|
8.0 | % | 9.0 | % | 9.0 | % | ||||||
|
Ultimate trend rate
|
4.5 | % | 4.5 | % | 4.5 | % | ||||||
|
Year in which ultimate trend rate is reached
|
2013 | 2013 | 2013 | |||||||||
The assumptions used to determine net periodic benefit cost for
each year were established at the end of each previous year
while the assumptions used to determine benefit obligations were
established at each year-end. The net periodic benefit
61
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
cost and the actuarial present value of benefit obligations are
based on actuarial assumptions that are reviewed on an annual
basis. The discount rate is developed based on a portfolio of
high-quality, fixed-income debt instruments with maturities that
approximate the expected payment of plan obligations. The
overall expected return on plan assets is developed from the
expected future returns for each asset category, weighted by the
target allocation of pension assets to that asset category.
The Corporation’s investment strategy is to maximize
long-term returns at an acceptable level of risk through broad
diversification of plan assets in a variety of asset classes.
Asset classes and target allocations are determined by the
Corporation’s investment committee and include domestic and
foreign equities, fixed income, and other investments, including
hedge funds, real estate and private equity. Investment managers
are prohibited from investing in securities issued by the
Corporation unless indirectly held as part of an index strategy.
The majority of plan assets are highly liquid, providing ample
liquidity for benefit payment requirements. The current target
allocations for plan assets are 50% equity securities, 25% fixed
income securities (including cash and short-term investment
funds) and 25% to all other types of investments. Asset
allocations are rebalanced on a periodic basis throughout the
year to bring assets to within an acceptable range of target
levels.
The following table provides the fair value of the Plan’s
financial assets as of December 31, 2009 in accordance with
the fair value measurement hierarchy described in Note 1,
Summary of Significant Accounting Policies (in millions):
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
|
Cash and short-term investment funds
|
$ | 5 | $ | 39 | $ | — | $ | 44 | ||||||||
|
Equities:
|
||||||||||||||||
|
U.S. equities (domestic)
|
318 | — | — | 318 | ||||||||||||
|
International equities
(non-U.S.)
|
34 | 93 | — | 127 | ||||||||||||
|
Global equities (domestic and
non-U.S.)
|
19 | 117 | — | 136 | ||||||||||||
|
Fixed income:
|
||||||||||||||||
|
Treasury and government issued(a)
|
— | 74 | 3 | 77 | ||||||||||||
|
Government related(b)
|
— | 24 | 2 | 26 | ||||||||||||
|
Mortgage backed securities(c)
|
— | 60 | 1 | 61 | ||||||||||||
|
Corporate
|
— | 78 | 2 | 80 | ||||||||||||
|
Other:
|
||||||||||||||||
|
Hedge funds
|
— | — | 143 | 143 | ||||||||||||
|
Private equity funds
|
— | — | 29 | 29 | ||||||||||||
|
Real estate funds
|
6 | — | 14 | 20 | ||||||||||||
|
Diversified commodities funds
|
— | 11 | — | 11 | ||||||||||||
| $ | 382 | $ | 496 | $ | 194 | $ | 1,072 | |||||||||
| (a) | Includes securities issued and guaranteed by U.S. and non-U.S. governments. | |
| (b) | Primarily consists of securities issued by governmental agencies and municipalities. | |
| (c) | Comprised of U.S. residential and commercial mortgage backed securities. |
Cash and short-term investment funds consist of cash on hand and
short-term investment funds. The short-term investment funds
provide for daily investments and redemptions and are valued and
carried at a $1 net asset value (NAV) per fund share.
Equities consist of equity securities issued by U.S. and
non-U.S. corporations
as well as commingled investment funds that invest in equity
securities. Individually held equity securities are traded
actively on exchanges and price quotes for these shares are
readily available. Individual equity securities are classified
as Level 1. Commingled investment funds are investment
vehicles that are not publicly traded, but whose underlying
assets are publicly traded with price quotes readily available.
Commingled fund values reflect the NAV per fund
62
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
share, derived from the quoted prices in active markets of the
underlying securities. Equity commingled funds are classified as
Level 2.
Fixed income investments consist of securities issued by the
U.S. government,
non-U.S. governments,
governmental agencies, municipalities and corporations, and
agency and non-agency mortgage backed securities. This
investment category also includes commingled investment funds
that invest in fixed income securities. Individual fixed income
securities are generally priced on the basis of evaluated prices
from independent pricing services. Such prices are monitored and
provided by an independent, third-party custodial firm
safekeeping plan assets. Individual fixed income securities are
classified as Level 2 or 3. Commingled fund values reflect
the NAV per fund share, derived indirectly from observable
inputs or from quoted prices in less liquid markets of the
underlying securities. Fixed income commingled funds are
classified as Level 2.
Other investments consist of exchange-traded real estate
investment trust securities as well as commingled fund and
limited partnership investments in hedge funds, private equity,
real estate and diversified commodities. Exchange-traded
securities are classified as Level 1. Commingled fund
values reflect the NAV per fund share and are classified as
Level 2 or 3. Private equity and real estate limited
partnership values reflect information reported by the fund
managers, which include inputs such as cost, operating results,
discounted future cash flows, market based comparable data and
independent appraisals from third-party sources with
professional qualifications. Hedge funds, private equity and
non-exchange-traded real estate investments are classified as
Level 3.
The following table provides changes in financial assets that
are measured at fair value based on Level 3 inputs that are
held by institutional funds classified as (in millions):
|
Private
|
Real
|
|||||||||||||||||||
|
Fixed
|
Hedge
|
Equity
|
Estate
|
|||||||||||||||||
| Income* | Funds | Funds | Funds | Total | ||||||||||||||||
|
Balance at January 1, 2009
|
$ | 12 | $ | 127 | $ | 25 | $ | 20 | $ | 184 | ||||||||||
|
Actual return on plan assets:
|
||||||||||||||||||||
|
Related to assets held at December 31, 2009
|
4 | 15 | (4 | ) | (7 | ) | 8 | |||||||||||||
|
Related to assets sold during 2009
|
(1 | ) | 1 | — | — | — | ||||||||||||||
|
Purchases, sales or other settlements
|
(2 | ) | — | 8 | 1 | 7 | ||||||||||||||
|
Net transfers in and/or out of Level 3
|
(5 | ) | — | — | — | (5 | ) | |||||||||||||
|
Balance at December 31, 2009
|
$ | 8 | $ | 143 | $ | 29 | $ | 14 | $ | 194 | ||||||||||
| * | Fixed Income includes treasury and government issued, government related, mortgage backed and corporate securities. |
The Corporation has budgeted contributions of approximately
$145 million to its funded pension plans in 2010. The
Corporation has not budgeted any contributions to the trust
established for the unfunded plan.
Estimated future benefit payments for the funded and unfunded
pension plans and the postretirement medical plan, which reflect
expected future service, are as follows (in millions):
|
2010
|
$ | 78 | ||
|
2011
|
100 | |||
|
2012
|
77 | |||
|
2013
|
87 | |||
|
2014
|
90 | |||
|
Years 2015 to 2019
|
568 |
The Corporation also contributes to several defined contribution
plans for eligible employees. Employees may contribute a portion
of their compensation to the plans and the Corporation matches a
portion of the employee
63
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
contributions. The Corporation recorded expense of
$24 million in 2009, $22 million in 2008, and
$19 million in 2007 for contributions to these plans.
| 11. | Income Taxes |
The provision for (benefit from) income taxes consisted of:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Federal
|
||||||||||||
|
Current
|
$ | 39 | $ | 10 | $ | 2 | ||||||
|
Deferred
|
(284 | ) | (140 | ) | 62 | |||||||
|
State
|
(15 | ) | 10 | (149 | ) | |||||||
| (260 | ) | (120 | ) | (85 | )* | |||||||
|
Foreign
|
||||||||||||
|
Current
|
1,143 | 2,377 | 1,898 | |||||||||
|
Deferred
|
(168 | ) | 87 | 64 | ||||||||
| 975 | 2,464 | 1,962 | ||||||||||
|
Adjustment of deferred tax liability for foreign income tax rate
change
|
— | (4 | ) | (5 | ) | |||||||
|
Total provision for income taxes
|
$ | 715 | $ | 2,340 | $ | 1,872 | ||||||
| * | Includes a provision for an increase in the valuation allowance for foreign tax credit carryforwards of $81 million and a benefit from a decrease in the valuation allowance for state net operating loss carryforwards of $96 million. |
Income (loss) before income taxes consisted of the following:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
United States*
|
$ | (711 | ) | $ | (349 | ) | $ | (147 | ) | |||
|
Foreign**
|
2,233 | 5,046 | 3,972 | |||||||||
|
Total income before income taxes
|
$ | 1,522 | $ | 4,697 | $ | 3,825 | ||||||
| * | Includes substantially all of the Corporation’s interest expense and the results of hedging activities. | |
| ** | Foreign income includes the Corporation’s Virgin Islands and other operations located outside of the United States. |
64
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A summary of the components of deferred tax liabilities,
deferred tax assets and taxes deferred at December 31 follows:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Deferred tax liabilities
|
||||||||
|
Property, plant and equipment and investments
|
$ | 3,021 | $ | 2,918 | ||||
|
Deferred taxes on undistributed earnings of foreign subsidiaries
|
174 | — | ||||||
|
Other
|
13 | 114 | ||||||
|
Total deferred tax liabilities
|
3,208 | 3,032 | ||||||
|
Deferred tax assets
|
||||||||
|
Net operating loss carryforwards
|
529 | 1,832 | ||||||
|
Tax credit carryforwards
|
860 | 458 | ||||||
|
Property, plant and equipment
|
1,575 | — | ||||||
|
Accrued liabilities
|
459 | 415 | ||||||
|
Asset retirement obligations
|
484 | 406 | ||||||
|
Other
|
339 | 227 | ||||||
|
Total deferred tax assets
|
4,246 | 3,338 | ||||||
|
Valuation allowance
|
(500 | ) | (266 | ) | ||||
|
Total deferred tax assets, net
|
3,746 | 3,072 | ||||||
|
Net deferred tax assets
|
$ | 538 | $ | 40 | ||||
Net deferred tax assets in the foregoing table include the
deferral of the tax consequences of the utilization of
approximately $4 billion of net operating loss
carryforwards in the United States during 2009 resulting from
intercompany transactions eliminated in consolidation related to
transfers of property, plant and equipment remaining within the
consolidated group. At December 31, 2009, the Corporation
has remaining federal net operating loss carryforwards in the
United States of approximately $49 million which will
expire in 2029. The remaining net operating loss carryforwards
relate primarily to foreign operations and expire in years after
2028. At December 31, 2009, the Corporation has alternative
minimum tax credit carryforwards of approximately
$192 million, which can be carried forward indefinitely.
Foreign tax credit carryforwards, which expire in 2010 to 2019
total $623 million. The Corporation also has approximately
$45 million of general business credits, substantially all
of which expire between 2012 and 2025.
In the consolidated balance sheet at December 31, deferred
tax assets and liabilities from the preceding table are netted
by taxing jurisdiction, combined with taxes deferred on
intercompany transactions, and are recorded in the following
captions:
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Other current assets
|
$ | 372 | $ | 188 | ||||
|
Deferred income taxes (long-term asset)
|
2,409 | 2,292 | ||||||
|
Accrued liabilities
|
(21 | ) | (199 | ) | ||||
|
Deferred income taxes (long-term liability)
|
(2,222 | ) | (2,241 | ) | ||||
|
Net deferred tax assets
|
$ | 538 | $ | 40 | ||||
65
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The difference between the Corporation’s effective income
tax rate and the United States statutory rate is reconciled
below:
| 2009 | 2008 | 2007 | ||||||||||
|
United States statutory rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
Effect of foreign operations
|
15.2 | 12.7 | 14.8 | |||||||||
|
State income taxes, net of Federal income tax
|
(1.2 | ) | 0.1 | (2.5 | ) | |||||||
|
Other
|
(2.0 | ) | 2.0 | 1.6 | ||||||||
|
Total
|
47.0 | % | 49.8 | % | 48.9 | % | ||||||
Below is a reconciliation of the beginning and ending amount of
unrecognized tax benefits (millions of dollars):
| 2009 | 2008 | |||||||
|
Balance at January 1
|
$ | 175 | $ | 165 | ||||
|
Additions based on tax positions taken in the current year
|
106 | 16 | ||||||
|
Additions based on tax positions of prior years
|
25 | 11 | ||||||
|
Reductions based on tax positions of prior years
|
(3 | ) | (15 | ) | ||||
|
Reductions due to settlements with taxing authorities
|
(20 | ) | (2 | ) | ||||
|
Reductions due to lapse of statutes of limitation
|
(12 | ) | — | |||||
|
Balance at December 31
|
$ | 271 | $ | 175 | ||||
At December 31, 2009, the unrecognized tax benefits include
$197 million, which if recognized, would affect the
Corporation’s effective income tax rate. Over the next
12 months, it is reasonably possible that the total amount
of unrecognized tax benefits could decrease by up to
$25 million due to settlements with taxing authorities.
The Corporation has not recognized deferred income taxes for
that portion of undistributed earnings of foreign subsidiaries
expected to be indefinitely reinvested in foreign operations.
The Corporation had undistributed earnings from foreign
subsidiaries expected to be indefinitely reinvested in foreign
operations of approximately $3.4 billion at
December 31, 2009. If these earnings were not indefinitely
reinvested, a deferred tax liability of approximately
$1.2 billion would be recognized, not accounting for the
potential utilization of foreign tax credits in the United
States.
The Corporation and its subsidiaries file income tax returns in
the United States and various foreign jurisdictions. The
Corporation is no longer subject to examinations by income tax
authorities in most jurisdictions for years prior to 2003.
Income taxes paid (net of refunds) in 2009, 2008, and 2007
amounted to $1,177 million, $2,420 million and
$1,826 million, respectively. The Corporation had accrued
interest and penalties of approximately $17 million as of
December 31, 2009 and approximately $6 million as of
December 31, 2008.
| 12. | Outstanding and Weighted Average Common Shares |
The following table provides the changes in the
Corporation’s outstanding common shares:
| 2009 | 2008 | 2007 | ||||||||||
| (Thousands of shares) | ||||||||||||
|
Balance at January 1
|
326,133 | 320,600 | 315,018 | |||||||||
|
Activity related to restricted common stock awards, net
|
680 | 1,148 | 941 | |||||||||
|
Employee stock options
|
416 | 3,852 | 4,566 | |||||||||
|
Conversion of preferred stock
|
— | 533 | 75 | |||||||||
|
Balance at December 31
|
327,229 | 326,133 | 320,600 | |||||||||
66
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
During 2008, the Corporation’s remaining 284,139
outstanding shares of 3% cumulative convertible preferred shares
were converted into common stock at a conversion rate of
1.8783 shares of common stock for each preferred share. The
Corporation issued 533,697 shares of common stock for the
conversion of these preferred shares and fractional shares were
settled by cash payments.
The weighted average number of common shares used in the basic
and diluted earnings per share computations for each year is
summarized below:
| 2009 | 2008 | 2007 | ||||||||||
| (Thousands of shares) | ||||||||||||
|
Common shares — basic
|
323,890 | 320,803 | 312,736 | |||||||||
|
Effect of dilutive securities
|
||||||||||||
|
Stock options
|
836 | 2,870 | 2,925 | |||||||||
|
Restricted common stock
|
1,239 | 1,815 | 3,066 | |||||||||
|
Convertible preferred stock
|
— | 359 | 585 | |||||||||
|
Common shares — diluted
|
325,965 | 325,847 | 319,312 | |||||||||
The calculation of weighted average common shares excludes the
effect of 4,050,000, 425,000 and 715,000
out-of-the-money
options for 2009, 2008 and 2007, respectively. Cash dividends on
common stock totaled $0.40 per share ($0.10 per quarter) during
2009, 2008 and 2007.
| 13. | Leased Assets |
The Corporation and certain of its subsidiaries lease gasoline
stations, drilling rigs, tankers, office space and other assets
for varying periods under contractual obligations accounted for
as operating leases. Certain operating leases provide an option
to purchase the related property at fixed prices. At
December 31, 2009, future minimum rental payments
applicable to non-cancelable operating leases with remaining
terms of one year or more (other than oil and gas property
leases) are as follows (in millions):
|
2010
|
$ | 482 | ||
|
2011
|
341 | |||
|
2012
|
354 | |||
|
2013
|
357 | |||
|
2014
|
320 | |||
|
Remaining years
|
1,428 | |||
|
Total minimum lease payments
|
3,282 | |||
|
Less: income from subleases
|
144 | |||
|
Net minimum lease payments
|
$ | 3,138 | ||
Operating lease expenses for drilling rigs used to drill
development wells and successful exploration wells are
capitalized.
67
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Rental expense was as follows:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Total rental expense
|
$ | 266 | $ | 270 | $ | 266 | ||||||
|
Less: income from subleases
|
11 | 12 | 13 | |||||||||
|
Net rental expense
|
$ | 255 | $ | 258 | $ | 253 | ||||||
| 14. | Risk Management and Trading Activities |
In the normal course of its business, the Corporation is exposed
to commodity risks related to changes in the prices of crude
oil, natural gas, refined products and electricity, as well as
to changes in interest rates and foreign currency values. The
Corporation also has trading operations, principally through a
50% voting interest in a consolidated partnership, that are
exposed to commodity price risks primarily related to the prices
of crude oil, natural gas and refined products.
The Corporation maintains a control environment under the
direction of its chief risk officer and through its corporate
risk policy, which the Corporation’s senior management has
approved. Controls include volumetric, term and
value-at-risk
limits. The chief risk officer must approve the use of new
instruments or commodities. Risk limits are monitored and
reported on daily to business units and to senior management.
The Corporation’s risk management department also performs
independent verifications of sources of fair values and
validations of valuation models. These controls apply to all of
the Corporation’s risk management and trading activities,
including the consolidated trading partnership. The
Corporation’s treasury department is responsible for
administering foreign exchange and interest rate hedging
programs.
Following is a description of the Corporation’s activities
that use derivatives as part of their operations and strategies.
Derivatives include both financial instruments and forward
purchase and sale contracts. Gross notional amounts of both long
and short positions are presented in the volume tables below.
These amounts include long and short positions that offset in a
closed position and have not reached contractual maturity. Gross
notional amounts do not quantify risk or represent assets or
liabilities of the Corporation, but are used in the calculation
of cash settlements under the contracts.
Energy Marketing Activities:
In its
energy marketing activities the Corporation sells refined
petroleum products, natural gas and electricity principally to
commercial and industrial businesses at fixed and floating
prices for varying periods of time. Commodity contracts such as
futures, forwards, swaps and options, together with physical
assets such as storage, are used to obtain supply and reduce
margin volatility or lower costs related to sales contracts with
customers.
The table below shows the gross volume of the Corporation’s
energy marketing commodity contracts outstanding at
December 31, 2009:
|
Commodity Contracts
|
||||
|
Crude oil and refined products (millions of barrels)
|
34 | |||
|
Natural gas (millions of mcf)
|
1,876 | |||
|
Electricity (millions of megawatt hours)
|
166 |
At December 31, 2009, a portion of energy marketing
commodity contracts are designated as cash flow hedges to hedge
variability of expected future cash flows of forecasted supply
transactions. The length of time over which the Corporation
hedges exposure to variability in future cash flows is
predominantly two years or less. For contracts outstanding at
December 31, 2009, the maximum duration was five years. The
Corporation records the effective portion of changes in the fair
value of cash flow hedges as a component of other comprehensive
income. Amounts
68
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
recorded in Accumulated other comprehensive income are
reclassified into Cost of products sold in the same period that
the hedged item is recognized in earnings. The ineffective
portion of changes in fair value of cash flow hedges is
recognized immediately in Cost of products sold.
At December 31, 2009, the after-tax deferred losses
relating to energy marketing activities recorded in Accumulated
other comprehensive income were $303 million
($335 million at December 31, 2008). The Corporation
estimates that approximately $224 million of this amount
will be reclassified into earnings over the next twelve months.
During 2009, 2008 and 2007, the Corporation reclassified
after-tax income (losses) from Accumulated other comprehensive
income of $(596) million, $112 million and
$(81) million, respectively. The amount of gain (loss) from
hedge ineffectiveness reflected in earnings in 2009, 2008 and
2007 was $(2) million in 2009, less than $1 million in
2008 and $(5) million in 2007. The change in the fair value
of energy marketing cash flow hedges was $(564) million in
2009, $(255) million in 2008 and $(3) million in 2007.
The change in fair value of other energy marketing commodity
contracts that are not designated as hedges are recognized
currently in earnings. Revenues from the sales contracts are
recognized in Sales and other operating revenues, supply
contract purchases are recognized in Cost of products sold and
net settlements from financial derivatives are recognized in
Cost of products sold. Net realized and unrealized pre-tax gains
on derivative contracts not designated as hedges amounted to
$102 million in 2009.
Corporate Risk Management:
Corporate
risk management activities include transactions designed to
reduce risk in the selling prices of crude oil or natural gas
produced by the Corporation or to reduce exposure to foreign
currency movements. Generally, futures, swaps or option
strategies may be used to fix the forward selling price of a
portion of the Corporation’s crude oil or natural gas
production. Forward contracts may also be used to purchase
certain currencies in which the Corporation does business with
the intent of reducing exposure to foreign currency fluctuations.
The table below shows the gross volume of Corporate risk
management derivative instruments outstanding at
December 31, 2009:
|
Commodity contracts, primarily crude oil (millions of barrels)*
|
54 | |||
|
Foreign exchange contracts (millions of U.S. dollars)
|
872 |
| * | Includes gross volumes associated with the offsetting crude oil hedge positions. |
During 2008, the Corporation closed Brent crude oil cash flow
hedges covering 24,000 barrels per day through 2012 by
entering into offsetting contracts with the same counterparty.
As a result, the valuation of those contracts is no longer
subject to change due to price fluctuations. There were no other
open hedges of crude oil or natural gas production at
December 31, 2009. Hedging activities decreased Exploration
and Production earnings by $337 million in 2009,
$423 million in 2008 and $244 million in 2007. The
pre-tax amount of these hedge losses is reflected in Sales and
other operating revenue. The gain (loss) from hedge
ineffectiveness reflected in revenue was less than
$1 million in 2009, $(13) million in 2008 and
$6 million in 2007.
At December 31, 2009, the after-tax deferred losses in
Accumulated other comprehensive income relating to Corporate
risk management cash flow hedges were $941 million
($1,143 million at December 31, 2008). These deferred
losses result from the Brent crude oil hedges referred to above
that cover ongoing production of 24,000 barrels per day
from 2010 through 2012. The Corporation estimates that
approximately $335 million of this amount will be
reclassified into earnings over the next twelve months. The
pre-tax amount of deferred hedge losses is reflected in Accounts
payable and the related income tax benefits are recorded as
Deferred income tax assets on the balance sheet.
69
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The change in fair value of foreign exchange contracts are not
designated as hedges. Gains or losses in foreign exchange
contracts, maturing through 2010, are recognized immediately in
Other, net in revenues and non-operating income.
For the year ended December 31, 2009, net pre-tax
gains on derivative contracts used for Corporate risk management
and not designated as hedges amounted to the following (in
millions):
|
Commodity
|
$ | 9 | ||
|
Foreign exchange
|
86 | |||
|
Total
|
$ | 95 | ||
Trading Activities:
Trading activities
are conducted principally through a trading partnership in which
the Corporation has a 50% voting interest. This consolidated
entity intends to generate earnings through various strategies
primarily using energy commodities, securities and derivatives.
The Corporation also takes trading positions for its own account.
The table below shows the gross volume of the Corporation’s
trading derivative instruments outstanding at December 31,
2009:
|
Commodity Contracts
|
||||
|
Crude oil and refined products (millions of barrels)
|
2,251 | |||
|
Natural gas (millions of mcf)
|
6,927 | |||
|
Electricity (millions of megawatt hours)
|
6 | |||
|
Other Contracts (millions of U.S. dollars)
|
||||
|
Interest rate
|
495 | |||
|
Foreign exchange
|
335 |
For the year ended December 31, 2009, pre-tax gains
recorded in Sales and other operating revenues from trading
activities amounted to the following (in millions):
|
Commodity
|
$ | 196 | ||
|
Foreign exchange
|
23 | |||
|
Interest rate and other
|
17 | |||
|
Total
|
$ | 236 | ||
Fair Value Measurements:
The
Corporation determines fair value in accordance with the fair
value measurements accounting standard (ASC 820 — Fair
Value Measurements and Disclosures), which established a
hierarchy that categorizes the sources of inputs, which
generally range from quoted prices for identical instruments in
a principal trading market (Level 1) to estimates
determined using related market data (Level 3). Multiple
inputs may be used to measure fair value, however, the level of
fair value for each financial asset or liability presented below
is based on the lowest significant input level within this fair
value
70
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
hierarchy. The following table provides the fair value of the
Corporation’s financial assets and (liabilities) based on
this hierarchy:
|
Collateral and
|
||||||||||||||||||||
|
counterparty
|
||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | netting | December 31, | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Derivative contracts
|
||||||||||||||||||||
|
Assets
|
$ | 46 | $ | 1,139 | $ | 119 | $ | (366 | ) | $ | 938 | |||||||||
|
Liabilities
|
(151 | ) | (2,910 | ) | (36 | ) | 320 | (2,777 | ) | |||||||||||
|
Other assets and liabilities measured at fair value on a
recurring basis
|
||||||||||||||||||||
|
Assets
|
37 | 21 | 5 | — | 63 | |||||||||||||||
|
Liabilities
|
— | (66 | ) | (4 | ) | — | (70 | ) | ||||||||||||
|
2008
|
||||||||||||||||||||
|
Derivative contracts
|
||||||||||||||||||||
|
Assets
|
$ | 449 | $ | 1,795 | $ | 695 | $ | (1,023 | ) | $ | 1,916 | |||||||||
|
Liabilities
|
(397 | ) | (3,395 | ) | (556 | ) | 712 | (3,636 | ) | |||||||||||
|
Other assets and liabilities measured at fair value on a
recurring basis
|
||||||||||||||||||||
|
Assets
|
55 | — | 10 | — | 65 | |||||||||||||||
|
Liabilities
|
— | (17 | ) | — | — | (17 | ) | |||||||||||||
The following table provides changes in financial assets and
liabilities that are measured at fair value based on
Level 3 inputs:
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Balance at January 1
|
$ | 149 | $ | (4 | ) | |||
|
Unrealized gains (losses)
|
||||||||
|
Included in earnings
|
103 | 634 | ||||||
|
Included in other comprehensive income
|
15 | (351 | ) | |||||
|
Purchases, sales or other settlements during the period
|
(144 | ) | (37 | ) | ||||
|
Net transfers in to (out of) Level 3
|
(39 | ) | (93 | ) | ||||
|
Balance at December 31
|
$ | 84 | $ | 149 | ||||
71
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The table below reflects the gross and net fair values of the
Corporation’s derivative instruments as of
December 31, 2009:
|
Accounts
|
Accounts
|
|||||||
| Receivable | Payable | |||||||
| (Millions of dollars) | ||||||||
|
Derivative contracts designated as hedging instruments
|
||||||||
|
Commodity
|
$ | 748 | $ | (1,166 | ) | |||
|
Derivative contracts not designated as hedging instruments*
|
||||||||
|
Commodity
|
9,145 | (10,493 | ) | |||||
|
Foreign exchange
|
3 | (26 | ) | |||||
|
Other
|
12 | (14 | ) | |||||
|
Total derivative contracts not designated as hedging instruments
|
9,160 | (10,533 | ) | |||||
|
Gross fair value of derivative contracts
|
9,908 | (11,699 | ) | |||||
|
Master netting arrangements
|
(8,653 | ) | 8,653 | |||||
|
Cash collateral (received) posted
|
(317 | ) | 269 | |||||
|
Net fair value of derivative contracts
|
$ | 938 | $ | (2,777 | ) | |||
| * | Includes trading derivatives and derivatives used for risk management. |
The Corporation generally enters into master netting
arrangements to mitigate counterparty credit risk. Master
netting arrangements are standardized contracts that govern all
specified transactions with the same counterparty and allow the
Corporation to terminate all contracts upon occurrence of
certain events, such as a counterparty’s default or
bankruptcy. Where these arrangements provide the right of offset
and the Corporation’s intent and practice is to offset
amounts in the case of contract terminations, the Corporation
records fair value on a net basis.
The carrying amounts of the Corporation’s financial
instruments and derivatives are recorded at their fair values at
December 31, 2009 and 2008, while fixed rate long-term debt
is recorded at a carrying value of $4,467 million (fair
value of $5,073 million) at December 31, 2009 and a
carrying value of $3,103 million (fair value of
$3,031 million) at December 31, 2008.
Credit Risk:
The Corporation is exposed
to credit risks that may at times be concentrated with certain
counterparties or groups of counterparties. Accounts receivable
are generated from a diverse domestic and international customer
base. The Corporation’s net receivables at
December 31, 2009 are concentrated with counterparties as
follows: oil and gas companies — 14%, US government
entities — 13%, manufacturers — 12% and
domestic and foreign trading companies — 11%. The
Corporation reduces its risk related to certain counterparties
by using master netting arrangements and requiring collateral,
generally cash or letters of credit. The Corporation records the
cash collateral received or posted as an offset of the fair
value of derivatives executed with the same counterparty. At
December 31, 2009 and 2008, the Corporation is holding cash
from counterparties of approximately $317 million and
$705 million, respectively. The Corporation has posted cash
to counterparties at December 31, 2009 and 2008 of
approximately $269 million and $394 million,
respectively.
At December 31, 2009, the Corporation had a total of
$2,847 million of outstanding letters of credit, primarily
issued to satisfy margin requirements. Certain of the
Corporation’s agreements also contain contingent collateral
provisions that could require the Corporation to post additional
collateral if the Corporation’s credit rating declines. As
of December 31, 2009, the net liability related to
derivatives with contingent collateral provisions was
approximately $2,120 million before cash collateral posted
of approximately $260 million. At December 31, 2009,
all three major credit rating agencies that rate the
Corporation’s debt had assigned an investment grade rating.
If two of the three agencies were to downgrade the
Corporation’s rating to below investment grade, as of
December 31, 2009, the Corporation would be required to
post additional collateral of approximately $281 million.
72
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 15. | Guarantees and Contingencies |
At December 31, 2009, the Corporation’s guarantees
include $121 million of HOVENSA’s crude oil purchases
and $15 million of HOVENSA’s senior debt obligations.
In addition, the Corporation has $100 million in letters of
credit for which it is contingently liable. As a result, the
maximum potential amount of future payments that the Corporation
could be required to make under its guarantees is
$236 million at December 31, 2009 ($219 million
at December 31, 2008). The Corporation also has a
contingent purchase obligation expiring in April 2012, to
acquire the remaining interest in WilcoHess, a retail gasoline
station joint venture. As of December 31, 2009, the
estimated value of the purchase obligation is approximately
$184 million.
The Corporation is subject to loss contingencies with respect to
various lawsuits, claims and other proceedings, including
environmental matters. A liability is recognized in the
Corporation’s consolidated financial statements when it is
probable a loss has been incurred and the amount can be
reasonably estimated. If the risk of loss is probable, but the
amount cannot be reasonably estimated or the risk of loss is
only reasonably possible, a liability is not accrued; however,
the Corporation discloses the nature of those contingencies.
The Corporation, 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 similar lawsuits, many involving
water utilities or governmental entities, were filed in
jurisdictions across the United States against producers of MTBE
and petroleum refiners who produced gasoline containing MTBE,
including the Corporation. 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. In 2008, the
majority of the cases against the Corporation were settled. In
February 2010, the Corporation reached an agreement in principle
to settle all but three of the remaining cases. The three
unresolved cases consist of two cases that have been
consolidated for pre-trial purposes in the Southern District of
New York as part of a multi-district litigation proceeding and
an action brought in state court by the State of New Hampshire.
In 2007, a pre-tax charge of $40 million was recorded to
cover all of the known MTBE cases against the Corporation.
Over the last several years, many refiners have entered into
consent agreements to resolve the United States Environmental
Protection Agency’s (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 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. The EPA
initially contacted the Corporation and HOVENSA regarding the
Petroleum Refinery Initiative in August 2003. Negotiations with
the EPA and the relevant states and the Virgin Islands are
continuing and substantial progress has been made toward
resolving this matter for both the Corporation and HOVENSA.
While the effect on the Corporation of the Petroleum Refining
Initiative cannot be estimated until a final settlement is
reached and entered by a court, additional significant future
capital expenditures and operating expenses will likely be
incurred by HOVENSA over a number of years. The amount of
penalties, if any, is not expected to be material.
The United States Deep Water Royalty Relief Act of 1995 (the
Act) implemented a royalty relief program that relieves eligible
leases issued between November 28, 1995 and
November 28, 2000 from paying royalties on deepwater
production in Federal Outer Continental Shelf lands. The Act
does not impose any price thresholds in order to qualify for the
royalty relief. The U.S. Minerals Management Service (MMS)
created regulations that included pricing requirements to
qualify for the royalty relief provided in the Act. During the
period from 2003 to
73
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
2009, the Corporation accrued the royalties imposed by the MMS
regulations. The legality of the thresholds imposed by the MMS
was challenged in the federal courts and, in October 2009, the
U.S. Supreme Court decided not to review the appellate
court’s decision against the MMS. As a result, the
Corporation recognized a pre-tax gain of $143 million
($89 million after income taxes) in 2009 to reverse all
previously recorded royalties. The pre-tax gain is reported in
Other, net within the Statement of Consolidated Income.
The Corporation is also currently subject to certain other
existing claims, lawsuits and proceedings, which it considers
routine and incidental to its business. The Corporation believes
that there is only a remote likelihood that future costs related
to any of these other known contingent liability exposures would
have a material adverse impact on its financial position or
results of operations.
| 16. | Segment Information |
The Corporation has two operating segments that comprise the
structure used by senior management to make key operating
decisions and assess performance. These are (1) Exploration
and Production and (2) Marketing and Refining. The
Exploration and Production segment explores for, develops,
produces, purchases, transports and sells crude oil and natural
gas. The Marketing and Refining segment manufactures refined
petroleum products and purchases, trades and markets refined
petroleum products, natural gas and electricity.
The following table presents financial data by operating segment
for each of the three years ended December 31, 2009:
|
Exploration
|
Marketing
|
Corporate
|
||||||||||||||
| and Production | and Refining | and Interest | Consolidated(a) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
|
2009
|
||||||||||||||||
|
Operating revenues
|
||||||||||||||||
|
Total operating revenues(b)
|
$ | 7,259 | $ | 22,464 | $ | 1 | ||||||||||
|
Less: Transfers between affiliates
|
110 | — | — | |||||||||||||
|
Operating revenues from unaffiliated customers
|
$ | 7,149 | $ | 22,464 | $ | 1 | $ | 29,614 | ||||||||
|
Net income (loss) attributable to Hess Corporation
|
$ | 1,042 | $ | 127 | $ | (429 | ) | $ | 740 | |||||||
|
Equity in income (loss) of HOVENSA L.L.C.
|
$ | — | $ | (229 | ) | $ | — | $ | (229 | ) | ||||||
|
Interest expense
|
— | — | 360 | 360 | ||||||||||||
|
Depreciation, depletion and amortization
|
2,167 | 79 | 8 | 2,254 | ||||||||||||
|
Provision (benefit) for income taxes
|
944 | 24 | (253 | ) | 715 | |||||||||||
|
Investments in affiliates
|
57 | 856 | — | 913 | ||||||||||||
|
Identifiable assets
|
21,810 | 6,388 | 1,267 | 29,465 | ||||||||||||
|
Capital employed(c)
|
14,163 | 2,979 | 853 | 17,995 | ||||||||||||
|
Capital expenditures
|
2,800 | 83 | 35 | 2,918 | ||||||||||||
74
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Exploration
|
Marketing
|
Corporate
|
||||||||||||||
| and Production | and Refining | and Interest | Consolidated(a) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
|
2008
|
||||||||||||||||
|
Operating revenues
|
||||||||||||||||
|
Total operating revenues(b)
|
$ | 10,095 | $ | 31,273 | $ | 3 | ||||||||||
|
Less: Transfers between affiliates
|
237 | — | — | |||||||||||||
|
Operating revenues from unaffiliated customers
|
$ | 9,858 | $ | 31,273 | $ | 3 | $ | 41,134 | ||||||||
|
Net income (loss) attributable to Hess Corporation
|
$ | 2,423 | $ | 277 | $ | (340 | ) | $ | 2,360 | |||||||
|
Equity in income of HOVENSA L.L.C.
|
$ | — | $ | 44 | $ | — | $ | 44 | ||||||||
|
Interest expense
|
— | — | 267 | 267 | ||||||||||||
|
Depreciation, depletion and amortization
|
1,952 | 74 | 3 | 2,029 | ||||||||||||
|
Provision (benefit) for income taxes
|
2,365 | 162 | (187 | ) | 2,340 | |||||||||||
|
Investments in affiliates
|
57 | 1,070 | — | 1,127 | ||||||||||||
|
Identifiable assets
|
19,506 | 6,680 | 2,403 | 28,589 | ||||||||||||
|
Capital employed(c)
|
12,945 | 3,178 | 223 | 16,346 | ||||||||||||
|
Capital expenditures
|
4,251 | 149 | 38 | 4,438 | ||||||||||||
|
2007
|
||||||||||||||||
|
Operating revenues
|
||||||||||||||||
|
Total operating revenues(b)
|
$ | 7,933 | $ | 23,993 | $ | 2 | ||||||||||
|
Less: Transfers between affiliates
|
201 | — | — | |||||||||||||
|
Operating revenues from unaffiliated customers
|
$ | 7,732 | $ | 23,993 | $ | 2 | $ | 31,727 | ||||||||
|
Net income (loss) attributable to Hess Corporation
|
$ | 1,842 | $ | 300 | $ | (310 | ) | $ | 1,832 | |||||||
|
Equity in income of HOVENSA L.L.C.
|
$ | — | $ | 176 | $ | — | $ | 176 | ||||||||
|
Interest expense
|
— | — | 256 | 256 | ||||||||||||
|
Depreciation, depletion and amortization
|
1,503 | 68 | 5 | 1,576 | ||||||||||||
|
Provision (benefit) for income taxes
|
1,865 | 181 | (174 | ) | 1,872 | |||||||||||
|
Investments in affiliates
|
57 | 1,060 | — | 1,117 | ||||||||||||
|
Identifiable assets
|
17,008 | 6,667 | 2,456 | 26,131 | ||||||||||||
|
Capital employed(c)
|
11,349 | 3,130 | (499 | ) | 13,980 | |||||||||||
|
Capital expenditures
|
3,438 | 118 | 22 | 3,578 | ||||||||||||
| (a) | After elimination of transactions between affiliates, which are valued at approximate market prices. | |
| (b) | Sales and operating revenues are reported net of excise and similar taxes in the consolidated statement of income, which amounted to approximately $2,100 million, $2,200 million and $2,000 million in 2009, 2008 and 2007, respectively. | |
| (c) | Calculated as equity plus debt. |
75
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Financial information by major geographic area for each of the
three years ended December 31, 2009:
|
Asia and
|
||||||||||||||||||||
| United States | Europe | Africa | Other | Consolidated | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Operating revenues
|
$ | 24,611 | $ | 1,771 | $ | 1,898 | $ | 1,334 | $ | 29,614 | ||||||||||
|
Property, plant and equipment (net)
|
5,792 | 3,930 | 3,617 | 3,288 | 16,627 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Operating revenues
|
$ | 33,202 | $ | 3,488 | $ | 3,173 | $ | 1,271 | $ | 41,134 | ||||||||||
|
Property, plant and equipment (net)
|
5,319 | 3,674 | 4,139 | 3,139 | 16,271 | |||||||||||||||
|
2007
|
||||||||||||||||||||
|
Operating revenues
|
$ | 25,530 | $ | 2,647 | $ | 2,443 | $ | 1,107 | $ | 31,727 | ||||||||||
|
Property, plant and equipment (net)
|
3,611 | 3,749 | 4,599 | 2,675 | 14,634 | |||||||||||||||
| 17. | Related Party Transactions |
The following table presents related party transactions for the
year-ended December 31:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Purchases of petroleum products:
|
||||||||||||
|
HOVENSA*
|
$ | 3,659 | $ | 6,589 | $ | 5,238 | ||||||
|
Sales of petroleum products and crude oil:
|
||||||||||||
|
WilcoHess
|
1,634 | 2,590 | 2,014 | |||||||||
|
HOVENSA
|
530 | 701 | 213 | |||||||||
| * | The Corporation has agreed to purchase 50% of HOVENSA’s production of refined products at market prices, after sales by HOVENSA to unaffiliated parties. |
76
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
(Unaudited)
The Supplementary Oil and Gas Data that follows is presented in
accordance with ASC 932,
Disclosures about Oil and Gas
Producing Activities,
and includes (1) costs incurred,
capitalized costs and results of operations relating to oil and
gas producing activities, (2) net proved oil and gas
reserves, and (3) a standardized measure of discounted
future net cash flows relating to proved oil and gas reserves,
including a reconciliation of changes therein.
The Corporation produces crude oil, natural gas liquids
and/or
natural gas principally in Algeria, Azerbaijan, Denmark,
Equatorial Guinea, Gabon, Indonesia, Libya, Malaysia, Norway,
Russia, Thailand, the United Kingdom and the United States.
Exploration activities are also conducted, or are planned, in
additional countries.
Costs
Incurred in Oil and Gas Producing Activities
|
United
|
Asia and
|
|||||||||||||||||||
|
For the Years Ended December 31
|
Total | States | Europe | Africa | Other | |||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Property acquisitions
|
||||||||||||||||||||
|
Unproved
|
$ | 188 | $ | 184 | $ | 2 | $ | — | $ | 2 | ||||||||||
|
Proved*
|
74 | — | — | — | 74 | |||||||||||||||
|
Exploration
|
938 | 206 | 69 | 225 | 438 | |||||||||||||||
|
Production and development capital expenditures**
|
1,918 | 807 | 513 | 255 | 343 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Property acquisitions
|
||||||||||||||||||||
|
Unproved
|
$ | 684 | $ | 642 | $ | — | $ | — | $ | 42 | ||||||||||
|
Proved*
|
300 | 87 | — | 210 | 3 | |||||||||||||||
|
Exploration
|
1,134 | 408 | 121 | 275 | 330 | |||||||||||||||
|
Production and development capital expenditures**
|
2,867 | 1,042 | 881 | 451 | 493 | |||||||||||||||
|
2007
|
||||||||||||||||||||
|
Property acquisitions
|
||||||||||||||||||||
|
Unproved
|
$ | 325 | $ | 316 | $ | — | $ | 1 | $ | 8 | ||||||||||
|
Proved*
|
137 | 137 | — | — | — | |||||||||||||||
|
Exploration
|
719 | 421 | 65 | 77 | 156 | |||||||||||||||
|
Production and development capital expenditures**
|
2,751 | 690 | 764 | 698 | 599 | |||||||||||||||
| * | Includes wells, equipment and facilities acquired with proved reserves. | |
| ** | Also includes $(9) million, $344 million and $146 million in 2009, 2008 and 2007, respectively, related to the accruals and revisions for asset retirement obligations. |
Capitalized
Costs Relating to Oil and Gas Producing Activities
| At December 31 | ||||||||
| 2009 | 2008 | |||||||
| (Millions of dollars) | ||||||||
|
Unproved properties
|
$ | 2,347 | $ | 2,265 | ||||
|
Proved properties
|
3,121 | 3,009 | ||||||
|
Wells, equipment and related facilities
|
22,118 | 20,058 | ||||||
|
Total costs
|
27,586 | 25,332 | ||||||
|
Less: reserve for depreciation, depletion, amortization and
lease impairment
|
12,273 | 10,269 | ||||||
|
Net capitalized costs
|
$ | 15,313 | $ | 15,063 | ||||
77
Table of Contents
Results
of Operations for Oil and Gas Producing Activities
The results of operations shown below exclude non-oil and gas
producing activities, primarily gains on sales of oil and gas
properties, interest expense, gains and losses resulting from
foreign exchange transactions and other non-operating income.
Therefore, these results are on a different basis than the net
income from Exploration and Production operations reported in
management’s discussion and analysis of results of
operations and in Note 16, Segment Information, in the
notes to the financial statements.
|
United
|
Asia and
|
|||||||||||||||||||
|
For the Years Ended December 31
|
Total | States | Europe | Africa | Other | |||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Sales and other operating revenues
|
||||||||||||||||||||
|
Unaffiliated customers
|
$ | 6,725 | $ | 1,501 | $ | 1,827 | $ | 2,193 | $ | 1,204 | ||||||||||
|
Inter-company
|
110 | 110 | — | — | — | |||||||||||||||
|
Total revenues
|
6,835 | 1,611 | 1,827 | 2,193 | 1,204 | |||||||||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Production expenses, including related taxes(a)
|
1,805 | 431 | 642 | 480 | 252 | |||||||||||||||
|
Exploration expenses, including dry holes and lease impairment
|
829 | 383 | 75 | 159 | 212 | |||||||||||||||
|
General, administrative and other expenses
|
255 | 130 | 45 | 22 | 58 | |||||||||||||||
|
Depreciation, depletion and amortization(b)
|
2,167 | 503 | 473 | 821 | 370 | |||||||||||||||
|
Total costs and expenses
|
5,056 | 1,447 | 1,235 | 1,482 | 892 | |||||||||||||||
|
Results of operations before income taxes
|
1,779 | 164 | 592 | 711 | 312 | |||||||||||||||
|
Provision for income taxes
|
904 | 64 | 185 | 514 | 141 | |||||||||||||||
|
Results of operations
|
$ | 875 | $ | 100 | $ | 407 | $ | 197 | $ | 171 | ||||||||||
|
2008
|
||||||||||||||||||||
|
Sales and other operating revenues
|
||||||||||||||||||||
|
Unaffiliated customers
|
$ | 9,569 | $ | 1,415 | $ | 3,435 | $ | 3,580 | $ | 1,139 | ||||||||||
|
Inter-company
|
237 | 237 | — | — | — | |||||||||||||||
|
Total revenues
|
9,806 | 1,652 | 3,435 | 3,580 | 1,139 | |||||||||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Production expenses, including related taxes(c)
|
1,872 | 373 | 811 | 465 | 223 | |||||||||||||||
|
Exploration expenses, including dry holes and lease impairment
|
725 | 305 | 45 | 186 | 189 | |||||||||||||||
|
General, administrative and other expenses
|
302 | 159 | 86 | 19 | 38 | |||||||||||||||
|
Depreciation, depletion and amortization(d)
|
1,952 | 238 | 591 | 888 | 235 | |||||||||||||||
|
Total costs and expenses
|
4,851 | 1,075 | 1,533 | 1,558 | 685 | |||||||||||||||
|
Results of operations before income taxes
|
4,955 | 577 | 1,902 | 2,022 | 454 | |||||||||||||||
|
Provision for income taxes
|
2,490 | 223 | 920 | 1,181 | 166 | |||||||||||||||
|
Results of operations
|
$ | 2,465 | $ | 354 | $ | 982 | $ | 841 | $ | 288 | ||||||||||
78
Table of Contents
|
United
|
Asia and
|
|||||||||||||||||||
|
For the Years Ended December 31
|
Total | States | Europe | Africa | Other | |||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2007
|
||||||||||||||||||||
|
Sales and other operating revenues
|
||||||||||||||||||||
|
Unaffiliated customers
|
$ | 7,297 | $ | 1,010 | $ | 2,670 | $ | 2,609 | $ | 1,008 | ||||||||||
|
Inter-company
|
201 | 201 | — | — | — | |||||||||||||||
|
Total revenues
|
7,498 | 1,211 | 2,670 | 2,609 | 1,008 | |||||||||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Production expenses, including related taxes
|
1,581 | 280 | 723 | 381 | 197 | |||||||||||||||
|
Exploration expenses, including dry holes and lease impairment
|
515 | 302 | 43 | 90 | 80 | |||||||||||||||
|
General, administrative and other expenses
|
257 | 130 | 73 | 17 | 37 | |||||||||||||||
|
Depreciation, depletion and amortization(e)
|
1,503 | 187 | 548 | 593 | 175 | |||||||||||||||
|
Total costs and expenses
|
3,856 | 899 | 1,387 | 1,081 | 489 | |||||||||||||||
|
Results of operations before income taxes
|
3,642 | 312 | 1,283 | 1,528 | 519 | |||||||||||||||
|
Provision for income taxes
|
1,817 | 121 | 661 | 911 | 124 | |||||||||||||||
|
Results of operations
|
$ | 1,825 | $ | 191 | $ | 622 | $ | 617 | $ | 395 | ||||||||||
| (a) | Includes $20 million ($15 million after income taxes) for reductions in carrying value of materials inventory in Equatorial Guinea. | |
| (b) | Includes $52 million ($26 million after income taxes) for reductions in carrying value of two short lived fields and production equipment in the U.K. North Sea. | |
| (c) | Includes $15 million ($9 million after income taxes) of Gulf of Mexico hurricane related costs. | |
| (d) | Includes asset impairment charges of $30 million ($17 million after income taxes). | |
| (e) | Includes asset impairment charges of $112 million ($56 million after income taxes). |
Oil and
Gas Reserves
The Corporation’s proved oil and gas reserves are
calculated in accordance with SEC regulations and the
requirements of the FASB. Proved oil and gas reserves are
quantities, which by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be
economically producible from known reservoirs under existing
economic conditions, operating methods and government
regulations. The Corporation’s estimation of net
recoverable quantities of liquid hydrocarbons and natural gas is
a highly technical process performed by internal teams of
geoscience professionals and reservoir engineers. Estimates of
reserves were prepared by the use of standard engineering and
geoscience methods generally accepted in the petroleum industry.
The method or combination of methods used in the analysis of
each reservoir is based on the maturity of the reservoir, the
completeness of the subsurface data available at the time of the
estimate, the stage of reservoir development and the production
history. Where applicable, reliable technologies may be used in
reserve estimation, as defined in the SEC regulations. These
technologies, including computational methods, must have been
field tested and demonstrated to provide reasonably certain
results with consistency and repeatability in the formation
being evaluated or in an analogous formation.
Commencing in 2009, the product prices used in the estimation of
oil and gas reserves were the average oil and gas selling prices
during the twelve month period prior to the reporting date
determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period, except for prices set
in contractual arrangements. In order for reserves to be
classified as proved, any required government approvals must be
obtained and depending on the cost of the project, either senior
management or the board of directors must commit to fund the
development.
The Corporation’s proved reserves are subject to certain
risks and uncertainties. These risks include commodity price
risk, technical risk and political risk. Reference is made to
Item 1A,
Risk Factors Related to Our Business and
Operations
on page 11 of this
Form 10-K.
79
Table of Contents
Internal
Controls
The Corporation maintains internal controls over its oil and gas
reserve estimation process which are administered by the
Corporation’s Senior Vice President of E&P Technology
and its Chief Financial Officer. Estimates of reserves are
prepared by technical staff that work directly with the oil and
gas properties using standard reserve estimation guidelines,
definitions and methodologies. Each year, reserve estimates for
a selection of the Corporation’s assets are subject to
internal technical audits and reviews. In addition, an
independent third party reserve engineer reviews and audits a
significant portion of the Corporation’s reported reserves
(see below). Reserve estimates are reviewed by senior management
and the Board of Directors.
Qualifications
The person primarily responsible for overseeing the preparation
of the Corporation’s oil and gas reserves is Mr. Scott
Heck, Senior Vice President of E&P Technology.
Mr. Heck is a member of the Society of Petroleum Engineers
with 30 years of industry experience in oil and gas
reservoir management and reserve estimation.
Reserves
Audit
The Corporation engaged the consulting firm of DeGolyer and
MacNaughton (D&M) to perform an audit of the internally
prepared reserve estimates on certain fields aggregating
approximately 80% of 2009 year-end reported reserve
quantities on a barrel of oil equivalent basis. The purpose of
the report dated January 15, 2010 was to provide additional
assurance on the reasonableness of internally prepared reserve
estimates and compliance with SEC regulations. The D&M
letter report on the Corporation’s estimated oil and gas
reserves was prepared using standard geological and engineering
methods generally accepted in the petroleum industry. D&M
is an independent petroleum engineering consulting firm that has
been providing petroleum consulting services throughout the
world for over 70 years. The D&M letter report on the
Corporation’s December 31, 2009 oil and gas reserves
is included as an exhibit to this
Form 10-K.
While the D&M report should be read in its entirety, the
report concludes that for the properties reviewed by D&M,
the total net proved reserve estimates prepared by Hess and
audited by D&M, in the aggregate, did not differ
materially. The report also includes among other information,
the qualifications of the technical person primarily responsible
for overseeing such reserve audit.
Effect of
adopting new SEC requirements
The SEC issued a final rule on oil and gas reserve estimation
and disclosure effective for year-end 2009 reporting. The
SEC’s final rule was designed to modernize and update the
oil and gas reserve disclosure requirements to align them with
current industry practices and changes in technology. In January
2010, the FASB issued its final accounting standards update,
Extractive Industries — Oil and Gas (ASC 932), which
principally conformed existing FASB standards to the new SEC
guidelines. Since it was not practical to calculate reserve
estimates under both the old and new reserve estimation
standards as of year end, it is not possible to precisely
measure the effect of adopting the new SEC requirements on total
proved reserves at December 31, 2009. However, the
Corporation estimates that the effect of initially applying the
new rules, primarily due to application of the new reserve
definitions and the consideration of permitted technology, was
to increase year end 2009 total proved reserves by approximately
2%. The change in reserve estimates resulting from applying the
new rules is included in the table below as 2009 revisions and
additions to proved reserves. The Corporation estimates that the
effect of adopting the new rules on its net income in 2010 will
be an increase of approximately $80 million, after tax, due
to lower depreciation, depletion and amortization costs,
assuming 2010 budgeted production levels for the affected fields
occur as forecasted.
Proved
undeveloped reserves
The December 31, 2009 oil and gas reserve estimates
disclosed below include 374 million barrels of liquid
hydrocarbons and 1,276 million mcf of natural gas
classified as proved undeveloped reserves. Proved undeveloped
liquid reserves decreased in 2009, primarily due to the
commencement of production from the Shenzi Field in the
deepwater Gulf of Mexico. Proved undeveloped natural gas
reserves also decreased in 2009 due to the continuation of
development activities in Block
A-18
in the
JDA. In addition, as part of its normal production operations,
the
80
Table of Contents
Corporation’s drilling programs on existing fields resulted
in the reclassification of proved undeveloped reserves to
developed. In 2009, these changes occurred primarily at certain
fields in the United States, Equatorial Guinea, Azerbaijan and
Russia. For the year ended December 31, 2009, the
Corporation estimates that capital expenditures of approximately
$450 million were incurred to convert proved undeveloped
reserves to proved developed reserves. The Corporation is
involved in multiple long term projects that have staged
developments. Certain of these projects have proved reserves,
which have been classified as undeveloped for a period in excess
of five years, totaling approximately 145 million barrels
of oil equivalent, or 10% of year end 2009 total proved
reserves. The proved undeveloped reserves in excess of five
years are related to gas projects in Block
A-18
in the
JDA, Indonesia, and Norway that are being developed in phases to
satisfy long-term gas sales contracts and an oil project in
Azerbaijan that is still under development.
Following are the Corporation’s proved reserves for the
three years ended December 31, 2009:
| Crude Oil, Condensate and Natural Gas Liquids | Natural Gas | |||||||||||||||||||||||||||||||||||
|
Africa,
|
||||||||||||||||||||||||||||||||||||
|
United
|
Asia and
|
United
|
Asia and
|
|||||||||||||||||||||||||||||||||
| States | Europe | Africa | Other | Total | States | Europe | Other |
Total
|
||||||||||||||||||||||||||||
| (Millions of barrels) | (Millions of mcf) | |||||||||||||||||||||||||||||||||||
|
Net Proved Developed and Undeveloped Reserves
|
||||||||||||||||||||||||||||||||||||
|
At January 1, 2007
|
138 | 340 | 304 | 50 | 832 | 236 | 677 | 1,553 | 2,466 | |||||||||||||||||||||||||||
|
Revisions of previous estimates(b)
|
37 | 17 | 17 | 1 | 72 | 32 | 73 | 143 | 248 | |||||||||||||||||||||||||||
|
Extensions, discoveries and other additions
|
17 | 14 | 6 | 23 | 60 | 26 | 11 | 148 | 185 | |||||||||||||||||||||||||||
|
Improved recovery
|
22 | — | — | — | 22 | 13 | — | — | 13 | |||||||||||||||||||||||||||
|
Purchases of minerals in place
|
5 | — | — | — | 5 | 1 | — | — | 1 | |||||||||||||||||||||||||||
|
Sales of minerals in place
|
— | (6 | ) | — | — | (6 | ) | — | (4 | ) | — | (4 | ) | |||||||||||||||||||||||
|
Production
|
(15 | ) | (36 | ) | (42 | ) | (7 | ) | (100 | ) | (38 | ) | (101 | ) | (102 | ) | (241 | ) | ||||||||||||||||||
|
At December 31, 2007(a)
|
204 | 329 | 285 | 67 | 885 | (c) | 270 | 656 | 1,742 | 2,668 | ||||||||||||||||||||||||||
|
Revisions of previous estimates(b)
|
9 | 30 | 83 | 25 | 147 | 22 | 84 | 188 | 294 | |||||||||||||||||||||||||||
|
Extensions, discoveries and other additions
|
26 | 5 | 1 | — | 32 | 18 | — | 65 | 83 | |||||||||||||||||||||||||||
|
Improved recovery
|
1 | — | — | — | 1 | — | — | — | — | |||||||||||||||||||||||||||
|
Purchases of minerals in place
|
2 | — | — | — | 2 | — | — | — | — | |||||||||||||||||||||||||||
|
Sales of minerals in place
|
— | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
|
Production
|
(15 | ) | (32 | ) | (45 | ) | (5 | ) | (97 | ) | (34 | ) | (101 | ) | (137 | ) | (272 | ) | ||||||||||||||||||
|
At December 31, 2008(a)
|
227 | 332 | 324 | 87 | 970 | (c) | 276 | 639 | 1,858 | 2,773 | ||||||||||||||||||||||||||
|
Revisions of previous estimates(b)
|
22 | 28 | 34 | (7 | ) | 77 | 46 | 66 | 83 | 195 | ||||||||||||||||||||||||||
|
Extensions, discoveries and other additions
|
26 | 1 | — | — | 27 | 23 | — | — | 23 | |||||||||||||||||||||||||||
|
Improved recovery
|
— | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
|
Purchases of minerals in place
|
— | — | — | — | — | — | — | 101 | 101 | |||||||||||||||||||||||||||
|
Sales of minerals in place
|
— | — | — | — | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||
|
Production
|
(26 | ) | (31 | ) | (44 | ) | (6 | ) | (107 | ) | (39 | ) | (62 | ) | (169 | ) | (270 | ) | ||||||||||||||||||
|
At December 31, 2009
|
249 | 330 | 314 | 74 | 967 | (c) | 306 | (d) | 642 | 1,873 | 2,821 | |||||||||||||||||||||||||
|
Net Proved Developed Reserves
|
||||||||||||||||||||||||||||||||||||
|
At January 1, 2007
|
90 | 223 | 194 | 19 | 526 | 195 | 517 | 585 | 1,297 | |||||||||||||||||||||||||||
|
At December 31, 2007
|
101 | 201 | 201 | 15 | 518 | 199 | 519 | 654 | 1,372 | |||||||||||||||||||||||||||
|
At December 31, 2008
|
119 | 192 | 237 | 23 | 571 | 202 | 502 | 727 | 1,431 | |||||||||||||||||||||||||||
|
At December 31, 2009
|
154 | 171 | 241 | 27 | 593 | 205 | 417 | 923 | 1,545 | |||||||||||||||||||||||||||
81
Table of Contents
| Crude Oil, Condensate and Natural Gas Liquids | Natural Gas | |||||||||||||||||||||||||||||||||||
|
Africa,
|
||||||||||||||||||||||||||||||||||||
|
United
|
Asia and
|
United
|
Asia and
|
|||||||||||||||||||||||||||||||||
| States | Europe | Africa | Other | Total | States | Europe | Other |
Total
|
||||||||||||||||||||||||||||
| (Millions of barrels) | (Millions of mcf) | |||||||||||||||||||||||||||||||||||
|
Net Proved Undeveloped Reserves
|
||||||||||||||||||||||||||||||||||||
|
At January 1, 2007
|
48 | 117 | 110 | 31 | 306 | 41 | 160 | 968 | 1,169 | |||||||||||||||||||||||||||
|
At December 31, 2007
|
103 | 128 | 84 | 52 | 367 | 71 | 137 | 1,088 | 1,296 | |||||||||||||||||||||||||||
|
At December 31, 2008
|
108 | 140 | 87 | 64 | 399 | 74 | 137 | 1,131 | 1,342 | |||||||||||||||||||||||||||
|
At December 31, 2009
|
95 | 159 | 73 | 47 | 374 | 101 | 225 | 950 | 1,276 | |||||||||||||||||||||||||||
| (a) | Proved reserves in 2008 and 2007 were determined by D&M, an independent petroleum engineering consulting firm. | |
| (b) | Includes the impact of changes in selling prices on the reserve estimates for each year for production sharing contracts with cost recovery provisions. In 2009, revisions included reductions of approximately 18 million barrels of crude oil and 102 million mcf of natural gas relating to higher selling prices. In 2008, revisions included increases of approximately 59 million barrels of crude oil and 104 million mcf of natural gas relating to lower selling prices. In 2007 revisions included reductions of approximately 29 million barrels of crude oil and 104 million mcf of natural gas relating to higher selling prices. | |
| (c) | Includes 17 million barrels in 2009, 16 million barrels in 2008 and 20 million barrels in 2007 of crude oil reserves relating to noncontrolling interest owners of corporate joint ventures. | |
| (d) | Excludes approximately 480 million mcf of carbon dioxide gas for sale or use in company operations. |
Production
sharing contracts
The Corporation’s proved reserves include crude oil and
natural gas reserves relating to long-term supply agreements
with governments or authorities in which the Corporation has the
legal right to produce or has a revenue interest in the
production. Proved reserves from these production sharing
contracts for each of the three years ended December 31,
2009 are presented separately below, as well as volumes produced
and received during 2009, 2008 and 2007 from these production
sharing contracts.
| Crude Oil, Condensate and Natural Gas Liquids | Natural Gas | |||||||||||||||||||||||||||||||||||
|
Africa,
|
||||||||||||||||||||||||||||||||||||
|
United
|
Asia and
|
United
|
Asia and
|
|||||||||||||||||||||||||||||||||
| States | Europe | Africa | Other | Total | States | Europe | Other | Total | ||||||||||||||||||||||||||||
| (Millions of barrels) | (Millions of mcf) | |||||||||||||||||||||||||||||||||||
|
Production Sharing Contracts
|
||||||||||||||||||||||||||||||||||||
|
Proved Reserves
|
||||||||||||||||||||||||||||||||||||
|
At December 31, 2007
|
— | — | 154 | 63 | 217 | — | — | 1,519 | 1,519 | |||||||||||||||||||||||||||
|
At December 31, 2008
|
— | — | 188 | 82 | 270 | — | — | 1,604 | 1,604 | |||||||||||||||||||||||||||
|
At December 31, 2009
|
— | — | 161 | 68 | 229 | — | — | 1,599 | 1,599 | |||||||||||||||||||||||||||
|
Production
|
||||||||||||||||||||||||||||||||||||
|
2007
|
— | — | 33 | 7 | 40 | — | — | 67 | 67 | |||||||||||||||||||||||||||
|
2008
|
— | — | 37 | 4 | 41 | — | — | 103 | 103 | |||||||||||||||||||||||||||
|
2009
|
— | — | 36 | 5 | 41 | — | — | 136 | 136 | |||||||||||||||||||||||||||
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
Future net cash flows are calculated by applying prescribed oil
and gas selling prices used in determining year-end reserve
estimates (adjusted for price changes provided by contractual
arrangements) to estimated future production of proved oil and
gas reserves, less estimated future development and production
costs, which are based on year-end costs and existing economic
assumptions. Future income tax expenses are computed by applying
the appropriate year-end statutory tax rates to the pre-tax net
cash flows relating to the Corporation’s proved oil and gas
reserves. Future net cash flows are discounted at the prescribed
rate of 10%. The discounted future net cash flow estimates do
not include exploration expenses, interest expense or corporate
general and administrative expenses. The selling prices of crude
oil and natural gas are highly volatile. The prices which are
required to be used for the
82
Table of Contents
discounted future net cash flows do not include the effects of
hedges and may not be representative of future selling prices.
The future net cash flow estimates could be materially different
if other assumptions were used.
|
United
|
Asia and
|
|||||||||||||||||||
|
At December 31
|
Total | States | Europe | Africa | Other | |||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Future revenues
|
$ | 65,275 | $ | 14,047 | $ | 20,298 | $ | 18,615 | $ | 12,315 | ||||||||||
|
Less:
|
||||||||||||||||||||
|
Future production costs
|
18,336 | 4,037 | 7,289 | 4,154 | 2,856 | |||||||||||||||
|
Future development costs
|
11,041 | 2,532 | 3,829 | 1,798 | 2,882 | |||||||||||||||
|
Future income tax expenses
|
17,976 | 2,744 | 5,114 | 8,601 | 1,517 | |||||||||||||||
| 47,353 | 9,313 | 16,232 | 14,553 | 7,255 | ||||||||||||||||
|
Future net cash flows
|
17,922 | 4,734 | 4,066 | 4,062 | 5,060 | |||||||||||||||
|
Less: discount at 10% annual rate
|
6,521 | 2,106 | 1,653 | 841 | 1,921 | |||||||||||||||
|
Standardized measure of discounted future net cash flows
|
$ | 11,401 | $ | 2,628 | $ | 2,413 | $ | 3,221 | $ | 3,139 | ||||||||||
|
2008
|
||||||||||||||||||||
|
Future revenues
|
$ | 46,846 | $ | 9,801 | $ | 15,757 | $ | 12,332 | $ | 8,956 | ||||||||||
|
Less:
|
||||||||||||||||||||
|
Future production costs
|
15,884 | 3,422 | 5,998 | 3,763 | 2,701 | |||||||||||||||
|
Future development costs
|
10,649 | 1,983 | 4,014 | 1,781 | 2,871 | |||||||||||||||
|
Future income tax expenses
|
9,299 | 1,467 | 2,741 | 4,440 | 651 | |||||||||||||||
| 35,832 | 6,872 | 12,753 | 9,984 | 6,223 | ||||||||||||||||
|
Future net cash flows
|
11,014 | 2,929 | 3,004 | 2,348 | 2,733 | |||||||||||||||
|
Less: discount at 10% annual rate
|
4,050 | 1,602 | 984 | 493 | 971 | |||||||||||||||
|
Standardized measure of discounted future net cash flows
|
$ | 6,964 | $ | 1,327 | $ | 2,020 | $ | 1,855 | $ | 1,762 | ||||||||||
|
2007
|
||||||||||||||||||||
|
Future revenues
|
$ | 94,955 | $ | 18,876 | $ | 32,778 | $ | 28,960 | $ | 14,341 | ||||||||||
|
Less:
|
||||||||||||||||||||
|
Future production costs
|
17,862 | 2,733 | 7,569 | 4,770 | 2,790 | |||||||||||||||
|
Future development costs
|
10,118 | 1,472 | 4,329 | 1,640 | 2,677 | |||||||||||||||
|
Future income tax expenses
|
33,833 | 5,291 | 12,083 | 14,309 | 2,150 | |||||||||||||||
| 61,813 | 9,496 | 23,981 | 20,719 | 7,617 | ||||||||||||||||
|
Future net cash flows
|
33,142 | 9,380 | 8,797 | 8,241 | 6,724 | |||||||||||||||
|
Less: discount at 10% annual rate
|
11,237 | 3,792 | 2,826 | 2,155 | 2,464 | |||||||||||||||
|
Standardized measure of discounted future net cash flows
|
$ | 21,905 | $ | 5,588 | $ | 5,971 | $ | 6,086 | $ | 4,260 | ||||||||||
83
Table of Contents
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
|
For the Years Ended December 31
|
2009 | 2008 | 2007 | |||||||||
| (Millions of dollars) | ||||||||||||
|
Standardized measure of discounted future net cash flows at
beginning of year
|
$ | 6,964 | $ | 21,905 | $ | 12,361 | ||||||
|
Changes during the year
|
||||||||||||
|
Sales and transfers of oil and gas produced during year, net of
production costs
|
(5,030 | ) | (7,934 | ) | (5,917 | ) | ||||||
|
Development costs incurred during year
|
1,927 | 2,523 | 2,605 | |||||||||
|
Net changes in prices and production costs applicable to future
production
|
7,484 | (28,627 | ) | 18,646 | ||||||||
|
Net change in estimated future development costs
|
(227 | ) | (1,056 | ) | (2,554 | ) | ||||||
|
Extensions and discoveries (including improved recovery) of oil
and gas reserves, less related costs
|
426 | 334 | 3,173 | |||||||||
|
Revisions of previous oil and gas reserve estimates
|
1,855 | 1,730 | 4,036 | |||||||||
|
Net purchases (sales) of minerals in place, before income taxes
|
165 | 18 | (50 | ) | ||||||||
|
Accretion of discount
|
1,235 | 4,109 | 2,233 | |||||||||
|
Net change in income taxes
|
(4,061 | ) | 13,859 | (9,259 | ) | |||||||
|
Revision in rate or timing of future production and other changes
|
663 | 103 | (3,369 | ) | ||||||||
|
Total
|
4,437 | (14,941 | ) | 9,544 | ||||||||
|
Standardized measure of discounted future net cash flows at end
of year
|
$ | 11,401 | $ | 6,964 | $ | 21,905 | ||||||
84
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
(Unaudited)
Quarterly results of operations for the years ended December 31:
|
Sales and
|
Net
|
|||||||||||||||
|
Other
|
Income (Loss)
|
Diluted Net
|
||||||||||||||
|
Operating
|
Gross
|
Attributable to
|
Income (Loss)
|
|||||||||||||
| Revenues | Profit(a) | Hess Corporation | per Share | |||||||||||||
| (Million of dollars, except per share data) | ||||||||||||||||
|
2009
|
||||||||||||||||
|
First
|
$ | 6,915 | $ | 533 | $ | (59 | )(b) | $ | (.18 | ) | ||||||
|
Second
|
6,751 | 756 | 100 | (c) | .31 | |||||||||||
|
Third
|
7,270 | 832 | 341 | (d) | 1.05 | |||||||||||
|
Fourth
|
8,678 | 1,282 | 358 | (e) | 1.10 | |||||||||||
|
2008
|
||||||||||||||||
|
First
|
$ | 10,647 | $ | 1,788 | $ | 759 | $ | 2.34 | ||||||||
|
Second
|
11,711 | 2,084 | 900 | 2.76 | ||||||||||||
|
Third
|
11,396 | 1,904 | 775 | 2.37 | ||||||||||||
|
Fourth
|
7,380 | 656 | (74 | )(f) | (.23 | ) | ||||||||||
| (a) | Gross profit represents sales and other operating revenues, less cost of products sold, production expenses, marketing expenses, other operating expenses and depreciation, depletion and amortization. | |
| (b) | Includes after-tax charges of $13 million related to asset impairments in the United Kingdom North Sea and $16 million for retirement benefits and employee severance costs. | |
| (c) | Includes after-tax charges of $31 million to reduce the carrying value of production equipment in the United Kingdom North Sea and materials inventory in Equatorial Guinea and the United States. | |
| (d) | Includes after-tax gains of $101 million primarily relating to the resolution of a royalty dispute. | |
| (e) | Includes after- tax charges of $34 million for the repurchase of bonds and $10 million for pension plan settlements related to employee retirements. | |
| (f) | Includes after-tax charges of $17 million related to asset impairments in the United States and United Kingdom North Sea and $9 million associated with Hurricanes Gustav and Ike in the Gulf of Mexico. |
The results of operations for the periods reported herein should
not be considered as indicative of future operating results.
85
Table of Contents
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
Based upon their evaluation of the Corporation’s disclosure
controls and procedures (as defined in Exchange Act
Rules 13a-15(e)
and
15d-15(e))
as of December 31, 2009, John B. Hess, Chief Executive
Officer, and John P. Rielly, Chief Financial Officer, concluded
that these disclosure controls and procedures were effective as
of December 31, 2009.
There was no change in internal controls over financial
reporting identified in the evaluation required by paragraph
(d) of
Rules 13a-15
or
15d-15
in
the quarter ended December 31, 2009 that has materially
affected, or is reasonably likely to materially affect, internal
controls over financial reporting.
Management’s report on internal control over financial
reporting and the attestation report on the Corporation’s
internal controls over financial reporting are included in
Item 8 of this annual report on
Form 10-K.
| Item 9B. | Other Information |
None.
| Item 10. | Directors, Executive Officers and Corporate Governance |
Information relating to Directors is incorporated herein by
reference to “Election of Directors” from the
Registrant’s definitive proxy statement for the annual
meeting of stockholders to be held on May 5, 2010.
Information regarding executive officers is included in
Part I hereof.
The Corporation has adopted a Code of Business Conduct and
Ethics applicable to the Corporation’s directors, officers
(including the Corporation’s principal executive officer
and principal financial officer) and employees. The Code of
Business Conduct and Ethics is available on the
Corporation’s website. In the event that we amend or waive
any of the provisions of the Code of Business Conduct and Ethics
that relate to any element of the code of ethics definition
enumerated in Item 406(b) of
Regulation S-K,
we intend to disclose the same on the Corporation’s website
at www.hess.com.
Information relating to the audit committee is incorporated
herein by reference to “Election of Directors” from
the registrant’s definitive proxy statement for the annual
meeting of stockholders to be held on May 5, 2010.
| Item 11. | Executive Compensation |
Information relating to executive compensation is incorporated
herein by reference to “Election of Directors —
Executive Compensation and Other Information,” from the
Registrant’s definitive proxy statement for the annual
meeting of stockholders to be held on May 5, 2010.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Information pertaining to security ownership of certain
beneficial owners and management is incorporated herein by
reference to “Election of Directors — Ownership
of Voting Securities by Certain Beneficial Owners” and
“Election of Directors — Ownership of Equity
Securities by Management” from the Registrant’s
definitive proxy statement for the annual meeting of
stockholders to be held on May 5, 2010.
See Equity Compensation Plans in Item 5 for information
pertaining to securities authorized for issuance under equity
compensation plans.
86
Table of Contents
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Information relating to this item is incorporated herein by
reference to “Election of Directors” from the
Registrant’s definitive proxy statement for the annual
meeting of stockholders to be held on May 5, 2010.
| Item 14. | Principal Accounting Fees and Services |
Information relating to this item is incorporated by reference
to “Ratification of Selection of Independent Auditors”
from the Registrant’s definitive proxy statement for the
annual meeting of stockholders to be held on May 5, 2010.
| Item 15. | Exhibits, Financial Statement Schedules |
| (a) | 1. and 2. Financial statements and financial statement schedules |
The financial statements filed as part of this Annual Report on
Form 10-K
are listed in the accompanying index to financial statements and
schedules in Item 8, Financial Statements and Supplementary
Data.
| 3. | Exhibits |
| 3(1) | Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit 3 of Registrant’s Form 10-Q for the three months ended June 30, 2006. | |||
| 3(2) | By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002. | |||
| 4(1) | Five-Year Credit Agreement dated as of December 10, 2004, as amended and restated as of May 12, 2006, among Registrant, certain subsidiaries of Registrant, J.P. Morgan Chase Bank, N.A. as lender and administrative agent, and the other lenders party thereto, incorporated by reference to Exhibit(4) of Form 10-Q of Registrant for the three months ended June 30, 2006. | |||
| 4(2) | Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. | |||
| 4(3) | First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999. | |||
| 4(4) | Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001. | |||
| 4(5) | Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002. | |||
| 4(6) | Indenture dated as of March 1, 2006 between Registrant and The Bank of New York Mellon as successor to JP Morgan Chase, as Trustee, including form of Note. Incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed with the Securities and Exchange Commission on March 1, 2006. | |||
| 4(7) | Form of 2014 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase as Trustee. Incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009. | |||
| 4(8) | Form of 2019 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase, as Trustee. Incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009. |
87
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| 4(9) | Form of 6.00% Note, incorporated by reference to Exhibit 4.1 to the Form 8-K filed on December 15, 2009. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request. | |||
| 10(1) | Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981. | |||
| 10(2) | Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990. | |||
| 10(3) | Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993. | |||
| 10(4) | Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998. | |||
| 10(5) | * | Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on February 10, 2009. | ||
| 10(6) | * | Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004. | ||
| 10(7) | * | Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006. | ||
| 10(8) | * | Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) of Form 10-Q of Registrant for the three months ended June 30, 2006. | ||
| 10(9) | * | Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989. | ||
| 10(10) | * | Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006. | ||
| 10(11) | * | Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002. | ||
| 10(12) | * | Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004. | ||
| 10(13) | * | 2008 Long Term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008. | ||
| 10(14) | * | Forms of Awards under Registrant’s 2008 Long Term Incentive Plan. | ||
| 10(15) | * | Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2007. | ||
| 10(16) | * | Amended and Restated Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and F. Borden Walker, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess. | ||
| 10(17) | * | Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than those referred to in Exhibit 10(15)). |
88
Table of Contents
| 10(18) | * | Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. | ||
| 10(19) | * | Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Form 8-K of Registrant filed January 7, 2009. | ||
| 10(20) | * | Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment. | ||
| 10(21) | * | Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999. | ||
| 10(22) | Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998. | |||
| 10(23) | Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998. | |||
| 21 | Subsidiaries of Registrant. | |||
| 23(1) | Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 26, 2010. | |||
| 23(2) | Consent of DeGolyer and MacNaughton dated February 26, 2010. | |||
| 31(1) | Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)). | |||
| 31(2) | Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)). | |||
| 32(1) | Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). | |||
| 32(2) | Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). | |||
| 99(1) | Letter report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consulting Firm, dated January 15, 2010, on proved reserves audit as of December 31, 2009 of certain properties attributable to Registrant. | |||
| 101(INS) | XBRL Instance Document | |||
| 101(SCH) | XBRL Schema Document | |||
| 101(CAL) | XBRL Calculation Linkbase Document | |||
| 101(LAB) | XBRL Label Linkbase Document | |||
| 101 (PRE) | XBRL Presentation Linkbase Document | |||
| 101(DEF) | XBRL Definition Linkbase Document |
| * | These exhibits relate to executive compensation plans and arrangements. |
| (b) | Reports on Form 8-K |
During the three months ended December 31, 2009, Registrant
filed or furnished the following report on
Form 8-K:
1. Filing dated October 29, 2009 reporting under
Items 2.02 and 9.01, a news release dated October 29,
2009 reporting results for the third quarter of 2009.
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SIGNATURES
Pursuant to the requirements of
Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on the
26th day of February 2010.
HESS CORPORATION
(Registrant)
(Registrant)
| By |
/s/
John
P. Rielly
|
(John P. Rielly)
Senior Vice President
and
Chief Financial
Officer
Pursuant to the requirements of
the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
||||
|
/s/
John
B. Hess
|
Director, Chairman of the Board and Chief Executive Officer
(Principal Executive Officer) |
February 26, 2010 | ||||
|
/s/
Samuel
W. Bodman
|
Director | February 26, 2010 | ||||
|
/s/
Nicholas
F. Brady
|
Director | February 26, 2010 | ||||
|
/s/
Gregory
P. Hill
|
Director | February 26, 2010 | ||||
|
/s/
Edith
E. Holiday
|
Director | February 26, 2010 | ||||
|
/s/
Thomas
H. Kean
|
Director | February 26, 2010 | ||||
|
/s/
Risa
Lavizzo-Mourey
|
Director | February 26, 2010 | ||||
|
/s/
Craig
G. Matthews
|
Director | February 26, 2010 | ||||
|
/s/
John
H. Mullin
|
Director | February 26, 2010 | ||||
|
/s/
Frank
A. Olson
|
Director | February 26, 2010 | ||||
|
/s/
John
P. Rielly
|
Senior Vice President and Chief
Financial Officer (Principal Financial and Accounting Officer) |
February 26, 2010 | ||||
|
/s/
Ernst
H. von Metzsch
|
Director | February 26, 2010 | ||||
|
/s/
F.
Borden Walker
|
Director | February 26, 2010 | ||||
|
/s/
Robert
N. Wilson
|
Director | February 26, 2010 | ||||
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Table of Contents
Schedule II
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
VALUATION
AND QUALIFYING ACCOUNTS
For the
Years Ended December 31, 2009, 2008 and 2007
| Additions | ||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
to Costs
|
Charged
|
Deductions
|
||||||||||||||||||
|
Balance
|
and
|
to Other
|
from
|
Balance
|
||||||||||||||||
|
Description
|
January 1 | Expenses | Accounts | Reserves | December 31 | |||||||||||||||
| (In millions) | ||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Losses on receivables
|
$ | 46 | $ | 13 | $ | — | $ | 5 | $ | 54 | ||||||||||
|
2008
|
||||||||||||||||||||
|
Losses on receivables
|
$ | 41 | $ | 9 | $ | — | $ | 4 | $ | 46 | ||||||||||
|
2007
|
||||||||||||||||||||
|
Losses on receivables
|
$ | 39 | $ | 5 | $ | — | $ | 3 | $ | 41 | ||||||||||
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EXHIBIT INDEX
| 3(1) | Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit(3) of Registrant’s Form 10-Q for the three months ended June 30, 2006. | |||
| 3(2) | By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002. | |||
| 4(1) | Five-Year Credit Agreement dated as of December 10, 2004, as amended and restated as of May 12, 2006, among Registrant, certain subsidiaries of Registrant, J.P. Morgan Chase Bank, N.A. as lender and administrative agent, and the other lenders party thereto, incorporated by reference to Exhibit(4) of Form 10-Q of Registrant for the three months ended June 30, 2006. | |||
| 4(2) | Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. | |||
| 4(3) | First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 7 3 / 8 % Notes due 2009 and 7 7 / 8 % Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999. | |||
| 4(4) | Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001. | |||
| 4(5) | Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002. | |||
| 4(6) | Indenture dated as of March 1, 2006 between Registrant and The Bank of New York Mellon as successor to JP Morgan Chase, as Trustee, including form of Note. Incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed with the Securities and Exchange Commission on March 1, 2006. | |||
| 4(7) | Form of 2014 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase as Trustee. Incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009. | |||
| 4(8) | Form of 2019 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase, as Trustee. Incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009. | |||
| 4(9) | Form of 6.00% Note, incorporated by reference to Exhibit 4.1 to the Form 8-K filed on December 15, 2009. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request. | |||
| 10(1) | Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981. | |||
| 10(2) | Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990. | |||
| 10(3) | Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993. | |||
| 10(4) | Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998. |
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| 10(5) | * | Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on February 10, 2009. | ||
| 10(6) | * | Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004. | ||
| 10(7) | * | Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006. | ||
| 10(8) | * | Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) of Form 10-Q of Registrant for the three months ended June 30, 2006. | ||
| 10(9) | * | Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989. | ||
| 10(10) | * | Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006. | ||
| 10(11) | * | Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002. | ||
| 10(12) | * | Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004. | ||
| 10(13) | * | 2008 Long Term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008. | ||
| 10(14) | * | Forms of Awards under Registrant’s 2008 Long Term Incentive Plan. | ||
| 10(15) | * | Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2007. | ||
| 10(16) | * | Amended and Restated Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and F. Borden Walker, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess. | ||
| 10(17) | * | Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than those referred to in Exhibit 10(15)). | ||
| 10(18) | * | Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. | ||
| 10(19) | * | Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Form 8-K of Registrant filed January 7, 2009. | ||
| 10(20) | * | Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment. | ||
| 10(21) | * | Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999. | ||
| 10(22) | Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998. | |||
| 10(23) | Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998. | |||
| 21 | Subsidiaries of Registrant. | |||
| 23(1) | Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 26, 2010. | |||
| 23(2) | Consent of DeGolyer and MacNaughton dated February 26, 2010. | |||
| 31(1) | Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)). |
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| 31(2) | Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)). | |||
| 32(1) | Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). | |||
| 32(2) | Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). | |||
| 99(1) | Letter report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consulting Firm, dated January 15, 2010, on proved reserves audit as of December 31, 2009 of certain properties attributable to Registrant. | |||
| 101(INS) | XBRL Instance Document | |||
| 101(SCH) | XBRL Schema Document | |||
| 101(CAL) | XBRL Calculation Linkbase Document | |||
| 101(LAB) | XBRL Label Linkbase Document | |||
| 101 (PRE) | XBRL Presentation Linkbase Document | |||
| 101(DEF) | XBRL Definition Linkbase Document |
| * | These exhibits relate to executive compensation plans and arrangements. |
TABLE OF CONTENTS
Part IItem 1A. Risk Factors Related To Our Business and OperationsItem 3. Legal ProceedingsItem 4. Submission Of Matters To A Vote Of Security HoldersPart IIItem 5. Market For The Registrant S Common Stock, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement Schedules