HESS CORP
10-Qs and 10-Ks
PROXIES
Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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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, 2010 |
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or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to |
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Commission File Number 1-1204
Hess Corporation
(Exact name of Registrant as
specified in its charter)
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DELAWARE
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13-4921002 | |
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(State or other jurisdiction
of
incorporation or organization) |
(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)
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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.
o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule
12b-2
of the
Exchange Act. (Check one):
| 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 $14,497,000,000
computed using the outstanding common shares and closing market
price on June 30, 2010.
At December 31, 2010, there were 337,680,780 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 4, 2011.
HESS
CORPORATION
Form 10-K
TABLE OF
CONTENTS
1
Table of Contents
PART I
Items 1
and 2.
Business and Properties
Hess Corporation (the Registrant) is a Delaware corporation,
incorporated in 1920. The Registrant and its subsidiaries
(collectively referred to as the Corporation or Hess) is a
global integrated energy company that operates in two segments,
Exploration and Production (E&P) and Marketing and Refining
(M&R). The E&P segment explores for, develops,
produces, purchases, transports and sells crude oil and natural
gas. These exploration and production activities take place
principally in Algeria, Australia, Azerbaijan, Brazil, Brunei,
China, Colombia, Denmark, Egypt, Equatorial Guinea, France,
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:
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Crude Oil,
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Total Barrels of
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Condensate &
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Oil
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Natural Gas
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Equivalent
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|||||||||||||||||||||||
| Liquids (c) | Natural Gas | (BOE)(a) | ||||||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||
| (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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180 | 154 | 199 | 205 | 213 | 188 | ||||||||||||||||||
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Europe(b)
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210 | 171 | 424 | 417 | 281 | 241 | ||||||||||||||||||
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Africa
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215 | 241 | 54 | 59 | 224 | 251 | ||||||||||||||||||
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Asia
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22 | 27 | 638 | 864 | 128 | 170 | ||||||||||||||||||
| 627 | 593 | 1,315 | 1,545 | 846 | 850 | |||||||||||||||||||
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Undeveloped
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United States
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124 | 95 | 81 | 101 | 138 | 112 | ||||||||||||||||||
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Europe(b)
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256 | 159 | 295 | 225 | 305 | 197 | ||||||||||||||||||
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Africa
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55 | 73 | 9 | 12 | 56 | 75 | ||||||||||||||||||
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Asia
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42 | 47 | 898 | 938 | 192 | 203 | ||||||||||||||||||
| 477 | 374 | 1,283 | 1,276 | 691 | 587 | |||||||||||||||||||
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Total
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United States
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304 | 249 | 280 | 306 | 351 | 300 | ||||||||||||||||||
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Europe(b)
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466 | 330 | 719 | 642 | 586 | 438 | ||||||||||||||||||
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Africa
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270 | 314 | 63 | 71 | 280 | 326 | ||||||||||||||||||
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Asia
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64 | 74 | 1,536 | 1,802 | 320 | 373 | ||||||||||||||||||
| 1,104 | 967 | 2,598 | 2,821 | 1,537 | 1,437 | |||||||||||||||||||
| (a) | Reflects natural gas reserves converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table on page 8. |
2
Table of Contents
| (b) | As a result of acquisitions in 2010, proved reserves in Norway represent 22% of the Corporation’s total reserves. Proved reserves in Norway at December 31, 2010 were as follows: |
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Crude Oil and
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Total Barrels of
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|||||||||||
| Natural Gas Liquids | Natural Gas | Oil Equivalent (BOE) | ||||||||||
| (Millions of barrels) | (Millions of mcf) | (Millions of barrels) | ||||||||||
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Developed
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97 | 157 | 123 | |||||||||
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Undeveloped
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167 | 247 | 208 | |||||||||
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Total
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264 | 404 | 331 | |||||||||
| (c) | Total natural gas liquids reserves at December 31, 2010, were 102 million barrels (54 million barrels developed and 48 million barrels undeveloped). Total natural gas liquids reserves at December 31, 2009, were 71 million barrels (41 million barrels developed and 30 million barrels undeveloped). |
On a barrel of oil equivalent (boe) basis, 45% of the
Corporation’s worldwide proved reserves are undeveloped at
December 31, 2010 (41% at December 31, 2009). Proved
reserves held under production sharing contracts at
December 31, 2010 totaled 15% of crude oil and natural gas
liquids and 51% of natural gas reserves (24% and 57%,
respectively, at December 31, 2009).
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 88 through 97 in the accompanying financial
statements for additional information on the Corporation’s
oil and gas reserves.
Worldwide crude oil, natural gas liquids and natural gas
production was as follows:
| 2010 | 2009 | 2008 | ||||||||||
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Crude oil (thousands of barrels per day)
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United States
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Offshore
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52 | 39 | 15 | |||||||||
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Onshore
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23 | 21 | 17 | |||||||||
| 75 | 60 | 32 | ||||||||||
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Europe
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United Kingdom
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19 | 21 | 29 | |||||||||
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Norway*
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16 | 13 | 16 | |||||||||
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Denmark
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11 | 12 | 11 | |||||||||
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Russia
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42 | 37 | 27 | |||||||||
| 88 | 83 | 83 | ||||||||||
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Africa
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Equatorial Guinea
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69 | 70 | 72 | |||||||||
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Algeria
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11 | 14 | 15 | |||||||||
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Gabon
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10 | 14 | 14 | |||||||||
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Libya
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23 | 22 | 23 | |||||||||
| 113 | 120 | 124 | ||||||||||
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Asia
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Azerbaijan
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7 | 8 | 7 | |||||||||
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Other
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6 | 8 | 6 | |||||||||
| 13 | 16 | 13 | ||||||||||
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Total
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289 | 279 | 252 | |||||||||
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Natural gas liquids (thousands of barrels per day)
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United States
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Offshore
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7 | 4 | 3 | |||||||||
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Onshore
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7 | 7 | 7 | |||||||||
| 14 | 11 | 10 | ||||||||||
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Europe*
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3 | 3 | 4 | |||||||||
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Asia
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1 | — | — | |||||||||
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Total
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18 | 14 | 14 | |||||||||
3
Table of Contents
| 2010 | 2009 | 2008 | ||||||||||
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Natural gas (thousands of mcf per day)
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United States
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Offshore
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70 | 55 | 37 | |||||||||
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Onshore
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38 | 38 | 41 | |||||||||
| 108 | 93 | 78 | ||||||||||
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Europe
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United Kingdom
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93 | 118 | 223 | |||||||||
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Norway*
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29 | 21 | 22 | |||||||||
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Denmark
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12 | 12 | 10 | |||||||||
| 134 | 151 | 255 | ||||||||||
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Asia and Other
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Joint Development Area of Malaysia/Thailand (JDA)
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282 | 294 | 185 | |||||||||
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Thailand
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85 | 85 | 87 | |||||||||
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Indonesia
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50 | 65 | 82 | |||||||||
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Other
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10 | 2 | 2 | |||||||||
| 427 | 446 | 356 | ||||||||||
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Total
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669 | 690 | 689 | |||||||||
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Barrels of oil equivalent (per day)**
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418 | 408 | 381 | |||||||||
| * | Norway production for 2010 included 14 thousand barrels per day of crude oil, 1 thousand barrels per day of natural gas liquids and 13 thousand mcf per day of natural gas from the Valhall Field. | |
| ** | Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table on page 8. |
A description of our significant E&P operations follows:
United
States
At December 31, 2010, 23% of the Corporation’s total
proved reserves were located in the United States. During 2010,
29% of the Corporation’s crude oil and natural gas liquids
production and 16% of its natural gas production were from
United States operations. The Corporation’s production in
the United States was from properties offshore in the Gulf of
Mexico, as well as onshore properties in the Williston Basin of
North Dakota and in the Permian Basin of Texas.
Offshore:
The Corporation’s
production offshore the United States was principally from the
Shenzi (Hess 28%), Llano (Hess 50%), Conger (Hess 38%), Baldpate
(Hess 50%), Hack Wilson (Hess 25%) and Penn State (Hess 50%)
fields. At the Shenzi Field, the operator is pursuing water
injection and additional development drilling opportunities.
However, development and exploration activities are currently
being affected by the uncertain regulatory environment in the
Gulf of Mexico. See Gulf of Mexico Update on page 12.
At the Pony project on Green Canyon Block 468 (Hess 100%),
the Corporation has signed a non-binding agreement in principle
with the owners on adjacent Green Canyon Block 512 that
outlines a proposal to jointly develop the Pony and Knotty Head
fields. Negotiation of a joint operating agreement and planning
for field development are underway. The agreement in principle
provides that Hess will be operator of the joint development.
The Corporation also commenced and subsequently suspended
drilling the Pony 3 appraisal well on Green Canyon
Block 469 in 2010. The Corporation is planning to resume
drilling in 2011 contingent upon receipt of necessary permits.
In the third quarter of 2010, the Corporation acquired an
additional 20% interest in the Tubular Bells oil and gas field
in the Gulf of Mexico. The Corporation now has a 40% working
interest in the field and is operator. Engineering and design
work for the field development progressed during 2010 and will
continue in 2011.
At December 31, 2010, the Corporation had interests in 306
blocks in the Gulf of Mexico, of which 272 were exploration
blocks comprising 1,069,000 net undeveloped acres, with an
additional 78,000 net acres held for production and
development operations.
4
Table of Contents
Onshore:
In North Dakota, the
Corporation holds more than 900,000 net acres in the Bakken
oil shale play (Bakken). In December 2010, the Corporation
acquired approximately 85,000 net acres in the Bakken
through the purchase of American Oil & Gas Inc.
(American Oil & Gas) through the issuance of
approximately 8.6 million shares of the Corporation’s
stock. Further, in December 2010, the Corporation acquired an
additional 167,000 net acres in the Bakken from TRZ Energy,
LLC for $1,075 million in cash. The Corporation is
currently operating 18 drilling rigs in the Bakken and is
expanding production and export facilities to accommodate future
production growth. In 2011, the Corporation plans to invest
$1.8 billion for drilling and infrastructure in the Bakken.
In Texas, the Corporation holds a 34% interest in the
Seminole-San Andres Unit and is operator. The Corporation
is developing a part of this producing field using tertiary
CO
2
flooding operations.
During 2010, the Corporation acquired approximately
90,000 net acres in the Eagle Ford shale formation in
Texas. The Corporation plans to drill an initial six exploration
wells, which will be followed by 12 appraisal wells. Exploration
drilling commenced in the fourth quarter of 2010.
In the Marcellus gas shale formation in Pennsylvania, the
Corporation is operator and holds a 100% interest on
approximately 53,000 net acres and holds a 50% non-operated
interest in approximately 38,000 net acres. There is
currently a drilling moratorium in the Delaware River Basin
area, where the majority of the Corporation’s acreage is
located. The moratorium is expected to remain in place until the
Delaware River Basin Commission establishes new drilling
regulations.
Europe
At December 31, 2010, 38% of the Corporation’s total
proved reserves were located in Europe (United Kingdom 6%,
Norway 22%, Denmark 3% and Russia 7%). During 2010, 30% of the
Corporation’s crude oil and natural gas liquids production
and 20% of its natural gas production were from European
operations.
United Kingdom:
Production of crude oil
and natural gas liquids from the United Kingdom North Sea was
principally from the Corporation’s non-operated interests
in the Nevis (Hess 27%), Bittern (Hess 28%), Schiehallion (Hess
16%) and Beryl (Hess 22%) fields. Natural gas production from
the United Kingdom was primarily from the Bacton Area (Hess
23%), Easington Catchment Area (Hess 30%), Everest (Hess 19%),
Beryl (Hess 22%), Nevis (Hess 27%) and Lomond (Hess 17%) fields.
The Corporation also has an 18% interest in the Central Area
Transmission System (CATS) pipeline and interests in the
Atlantic (Hess 25%) and Cromarty (Hess 90%) fields.
In September 2010, the Corporation disposed of all of its
interests in the Clair Field as part of an exchange for
additional interests in the Valhall and Hod fields in Norway as
further described below.
In February 2011, the Corporation completed the previously
announced sale of a package of natural gas producing assets in
the United Kingdom North Sea including its interests in the
Easington Catchment Area, the Bacton Area, the Everest Field and
the Lomond Field for approximately $350 million, after
closing adjustments. The sale of the Corporation’s interest
in the CATS pipeline is expected to close in the second quarter
of 2011.
Norway:
Substantially all of the 2010
Norwegian production was from the Corporation’s interest in
the Valhall Field (Hess 64%). The Corporation also holds an
interest in the Hod (Hess 63%), Snohvit (Hess 3%) and Snorre
(Hess 1%) fields. All four of the Corporation’s Norwegian
field interests are located offshore.
In September 2010, the Corporation exchanged its interests in
Gabon and the Clair Field in the United Kingdom for
additional interests of 28% and 25%, respectively, in the
Valhall and Hod fields in Norway. Also in September 2010, the
Corporation completed the acquisition of an additional 8%
interest in the Valhall Field and 13% interest in the Hod Field
for $507 million. After these transactions, the
Corporation’s interests in the Valhall and Hod fields are
now 64% and 63%, respectively.
A field redevelopment for Valhall commenced in 2007 and the
Valhall Flank Gas Lift project was sanctioned in 2009. In 2010,
the operator continued work on these projects, which are
expected to be completed and commissioned in 2011. In 2011,
further drilling is planned for Valhall, which will include the
addition of a
jack-up
rig
during the second half of the year.
5
Table of Contents
Denmark:
Crude oil and natural gas
production comes from the Corporation’s operated interest
in the South Arne Field (Hess 58%). In 2010, the Corporation
drilled two new production wells and sanctioned an additional
development phase at South Arne, which will include design,
construction and installation of two new platforms and related
infrastructure.
Russia:
The Corporation’s
activities in Russia are conducted through its interest in a
subsidiary operating in the Volga-Urals region. In the third
quarter of 2010, the Corporation acquired an additional 5%
interest in its subsidiary, increasing its ownership to 85%. As
of December 31, 2010, this subsidiary had exploration and
production rights in 18 license areas in the Samara and
Ulyanovsk territories.
France:
In 2010, the Corporation
entered into an agreement with Toreador Resources Corporation
(Toreador) under which it can invest in an initial exploration
phase and earn up to a 50% working interest in, and become
operator of, Toreador’s Paris Basin acreage. An initial six
exploration well program is scheduled to begin in 2011, with the
first well expected to spud in the first half of 2011.
Africa
At December 31, 2010, 18% of the Corporation’s total
proved reserves were located in Africa (Equatorial Guinea 6%,
Algeria 1% and Libya 11%). During 2010, 37% of the
Corporation’s crude oil and natural gas liquids production
was from African operations. In September 2010, the Corporation
disposed of all of its interests in Gabon as part of the
exchange for additional interests in the Valhall and Hod fields
in Norway.
Equatorial Guinea:
The Corporation is
the operator and owns an interest in Block G (Hess 85%) which
contains the Ceiba Field and Okume Complex. In 2010, a 4D
seismic survey was acquired covering the Okume Complex and the
Ceiba Field. This seismic data will be processed and evaluated
in 2011 in preparation for potential further development
drilling.
Algeria:
The Corporation has a 49%
interest in a venture with the Algerian national oil company
that redeveloped three oil fields. The Corporation also has an
interest in Bir El Msana (BMS) Block 401C.
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
drilled a down-dip appraisal well. In 2010, the Corporation
received a five year extension to the Area 54 license.
Egypt:
The Corporation has an interest
in the West Mediterranean Block 1 concession (West Med
Block) (Hess 55%). In September 2010, the Corporation recorded
an after-tax charge of $347 million to fully impair the
carrying value of its interest in the West Med Block and to
expense a previously capitalized well. See further discussion in
Management’s Discussion and Analysis of Financial Condition
and Results of Operations on page 29. The Corporation also
owns a 100% interest in Block 1 offshore Egypt in the North
Red Sea. The Corporation spud an exploration well on the North
Red Sea block in late December 2010, the completion of which may
be delayed by the current political unrest in Egypt. In December
2010, the Corporation entered a farm-out agreement that will,
subject to government approval, reduce its interest in the block
from 100% to 80%.
Ghana:
The Corporation holds a 100%
interest in the Deepwater Tano Cape Three Points License. In
2010, the Corporation acquired additional 3D seismic data and
plans to drill a second exploration well on this block in 2011.
Asia
At December 31, 2010, 21% of the Corporation’s total
proved reserves were located in the Asia region (JDA 9%,
Indonesia 6%, Thailand 3%, Azerbaijan 2% and Malaysia 1%).
During 2010, 4% of the Corporation’s crude oil and natural
gas liquids production and 64% of its natural gas production
were from its Asian 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. In 2011, the
operator will continue development of the block with further
drilling and construction of additional platform facilities.
6
Table of Contents
Malaysia:
The Corporation’s
production in Malaysia comes from its interest in Block PM301
(Hess 50%), which is adjacent to Block
A-18
of the
JDA where the natural gas is processed. The Corporation also
owns an interest in Block PM302 (Hess 50%) and Belud —
Block SB302 (Hess 40%). Through December 31, 2010 the
Corporation has drilled two wells on Block SB302 which were
natural gas discoveries. Technical and commercial evaluations
are underway to assess the development alternatives for this
block.
Indonesia:
The Corporation’s
natural gas production in Indonesia primarily comes from its
interests offshore in the Ujung Pangkah project (Hess 75%), and
the Natuna A Field (Hess 23%). In 2010, the Corporation
installed a new wellhead platform at Ujung Pangkah and will
install a new central processing platform in 2011 to expand oil
and water handling capacity. At the Natuna A Field the operator
is constructing a second wellhead platform and a central
processing platform, which is expected to be placed in service
in 2011. The Corporation also holds a 100% working interest in
the offshore Semai V Block, where it plans to drill three
exploration wells beginning in 2011. The Corporation owns a 100%
working interest in the offshore South Sesulu Block and a 49%
interest in the West Timor Block. In 2010, the Corporation sold
its interest in the Jambi Merang onshore natural gas development
project.
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-Chirag-Guneshli (ACG) fields (Hess 3%) in
the Caspian Sea and also owns an interest in the
Baku-Tiblisi-Ceyhan oil transportation pipeline (Hess 2%). In
2010, the Corporation sanctioned the Chirag Oil Development
project at ACG. This project includes construction and
installation of a production, drilling and living-quarters
platform and further development drilling.
Brunei:
The Corporation has a 14%
interest in Block
CA-1
(previously known as Block J). The Corporation expects the
operator to begin exploration drilling in the second half of
2011.
China:
The Corporation has signed a
joint study agreement with China National Petroleum Corporation
and two joint study agreements with Sinopec to evaluate
unconventional oil and gas resource opportunities in China.
Other
Exploration Areas
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). The Corporation has drilled all of the 16 commitment
wells on the block, 13 of which were natural gas discoveries. In
the fourth quarter of 2010, the Corporation commenced an
appraisal program that includes further drilling and flow
testing certain wells. In November 2010, the Corporation sold
its 50% interest in the WA-404-P Block located offshore Western
Australia.
Brazil:
The Corporation has a 40%
interest in block BM-S-22 located offshore Brazil. In early
2011, the operator completed drilling of a third exploration
well on this block, which did not encounter commercial
quantities of hydrocarbons. See further discussion in
Management’s Discussion and Analysis of Financial Condition
and Results of Operations on page 23. The Corporation also
had an interest in Block BM-ES-30 but reassigned its 30%
interest in 2010, pending government approval.
Peru:
The Corporation has an interest
in Block 64 in Peru (Hess 50%). In 2010, the Corporation
successfully drilled a sidetrack to an exploration well on this
block. Further evaluation work is planned for 2011.
Colombia:
The Corporation has interests
in offshore Blocks RC 6 and RC 7 (Hess 30%).
Sales
Commitments
In the E&P segment, the Corporation has no contracts or
agreements to sell fixed quantities of its crude oil production.
The Corporation has contracts to supply fixed quantities of
natural gas, principally relating to producing fields in Asia.
The most significant of these commitments relates to the JDA
where the minimum contract quantity of natural gas is estimated
at 107 million mcf per year based on current entitlements
under a natural gas sales contract expiring in 2027. There are
additional natural gas supply commitments on producing fields in
Thailand and Indonesia which currently total approximately
42 million mcf per year under contracts expiring in years
2021 through 2029. The Corporation is also currently committed
to supply 7 million mcf per year of natural gas from its
7
Table of Contents
share of production to a liquefied natural gas (LNG) processing
facility in Norway under a contract expiring in 2026. The
estimated total volume of natural gas subject to sales
commitments under these contracts is approximately
2,700 million mcf. The Corporation has not experienced any
significant constraints in satisfying the committed quantities
under these natural gas sales contracts and it anticipates being
able to meet future requirements from available proved and
probable reserves. In the United States there are no long-term
sales contracts for natural gas production from the E&P
segment.
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. These natural gas marketing activities are primarily
conducted in the eastern portion of the United States, where the
principal source of supply is purchased natural gas, not the
Corporation’s production from the E&P segment. The
Corporation has not experienced any significant constraints in
obtaining the required supply of purchased natural gas.
Average
selling prices and average production costs
| 2010 | 2009 | 2008 | ||||||||||
|
Average selling prices(a)
|
||||||||||||
|
Crude oil (per barrel)
|
||||||||||||
|
United States
|
$ | 75.02 | $ | 60.67 | $ | 96.82 | ||||||
|
Europe(b)
|
58.11 | 47.02 | 78.75 | |||||||||
|
Africa
|
65.02 | 48.91 | 78.72 | |||||||||
|
Asia
|
79.23 | 63.01 | 97.07 | |||||||||
|
Worldwide
|
66.20 | 51.62 | 82.04 | |||||||||
|
Natural gas liquids (per barrel)
|
||||||||||||
|
United States
|
$ | 47.92 | $ | 36.57 | $ | 64.98 | ||||||
|
Europe(b)
|
59.23 | 43.23 | 74.63 | |||||||||
|
Asia
|
63.50 | 46.48 | — | |||||||||
|
Worldwide
|
50.49 | 38.47 | 67.61 | |||||||||
|
Natural gas (per mcf)
|
||||||||||||
|
United States
|
$ | 3.70 | $ | 3.36 | $ | 8.61 | ||||||
|
Europe(b)
|
6.23 | 5.15 | 9.44 | |||||||||
|
Asia and other
|
5.93 | 5.06 | 5.24 | |||||||||
|
Worldwide
|
5.63 | 4.85 | 7.17 | |||||||||
|
Average production (lifting) costs per barrel of oil equivalent
produced(c)
|
||||||||||||
|
United States
|
$ | 12.61 | $ | 13.72 | $ | 18.46 | ||||||
|
Europe(b)
|
17.55 | 15.77 | 17.12 | |||||||||
|
Africa
|
11.00 | 10.93 | 10.22 | |||||||||
|
Asia
|
8.16 | 7.65 | 8.48 | |||||||||
|
Worldwide
|
12.61 | 12.12 | 13.43 | |||||||||
| (a) | Includes inter-company transfers valued at approximate market prices and the effect of the Corporation’s hedging activities. | |
| (b) | The average selling prices in Norway for 2010 were $79.47 per barrel for crude oil, $52.26 per barrel for natural gas liquids and $7.32 per mcf for natural gas. The average production (lifting) cost in Norway was $18.33 per barrel of oil equivalent produced. | |
| (c) | 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.
8
Table of Contents
Gross and
net undeveloped acreage at December 31, 2010
|
Undeveloped
|
||||||||
| Acreage(a) | ||||||||
| Gross | Net | |||||||
| (In thousands) | ||||||||
|
United States
|
3,650 | 2,478 | ||||||
|
Europe(c)
|
2,922 | 1,260 | ||||||
|
Africa
|
9,619 | 6,282 | ||||||
|
Asia and other
|
9,958 | 5,247 | ||||||
|
Total(b)
|
26,149 | 15,267 | ||||||
| (a) | Includes acreage held under production sharing contracts. | |
| (b) | Licenses covering approximately 19% of the Corporation’s net undeveloped acreage held at December 31, 2010 are scheduled to expire during the next three years pending the results of exploration activities. These scheduled expirations are largely in South America, Africa and the United States. | |
| (c) | Gross and net undeveloped acreage in Norway was 1,143 thousand and 259 thousand, respectively. |
Gross and
net developed acreage and productive wells at December 31,
2010
|
Developed
|
||||||||||||||||||||||||
|
Acreage
|
||||||||||||||||||||||||
|
Applicable to
|
Productive Wells* | |||||||||||||||||||||||
| Productive Wells | Oil | Gas | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
|
United States
|
628 | 538 | 1,114 | 573 | 61 | 46 | ||||||||||||||||||
|
Europe**
|
1,381 | 847 | 289 | 158 | 151 | 31 | ||||||||||||||||||
|
Africa
|
9,831 | 933 | 905 | 132 | — | — | ||||||||||||||||||
|
Asia and other
|
2,200 | 630 | 74 | 7 | 468 | 98 | ||||||||||||||||||
|
Total
|
14,040 | 2,948 | 2,382 | 870 | 680 | 175 | ||||||||||||||||||
| * | Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 20 gross wells and 15 net wells. | |
| ** | Gross and net developed acreage in Norway was 161 thousand and 45 thousand, respectively. Gross and net productive oil wells in Norway were 74 and 29, respectively. Gross and net productive gas wells in Norway were 9 and 1, respectively. |
Number of
net exploratory and development wells drilled
|
Net Exploratory
|
Net Development
|
|||||||||||||||||||||||
| Wells | Wells | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
|
Productive wells
|
||||||||||||||||||||||||
|
United States
|
— | — | 2 | 83 | 44 | 50 | ||||||||||||||||||
|
Europe*
|
1 | 7 | 11 | 18 | 12 | 11 | ||||||||||||||||||
|
Africa
|
1 | 1 | 1 | 11 | 23 | 23 | ||||||||||||||||||
|
Asia and other
|
6 | 8 | 5 | 7 | 12 | 25 | ||||||||||||||||||
| 8 | 16 | 19 | 119 | 91 | 109 | |||||||||||||||||||
|
Dry holes
|
||||||||||||||||||||||||
|
United States
|
5 | 4 | — | — | — | 1 | ||||||||||||||||||
|
Europe*
|
— | — | 3 | — | — | — | ||||||||||||||||||
|
Africa
|
2 | — | 2 | 1 | — | — | ||||||||||||||||||
|
Asia and other
|
2 | 2 | 1 | — | — | — | ||||||||||||||||||
| 9 | 6 | 6 | 1 | — | 1 | |||||||||||||||||||
|
Total
|
17 | 22 | 25 | 120 | 91 | 110 | ||||||||||||||||||
| * | Includes one net productive development well drilled in Norway in 2010. |
9
Table of Contents
Number of wells in process of drilling at December 31,
2010:
|
Gross
|
Net
|
|||||||
| Wells | Wells | |||||||
|
United States
|
41 | 17 | ||||||
|
Europe
|
11 | 10 | ||||||
|
Africa
|
16 | 2 | ||||||
|
Asia and other
|
12 | 3 | ||||||
|
Total
|
80 | 32 | ||||||
Number of net waterfloods and
pressure maintenance projects in process of installation at
December 31, 2010 — 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 | 2010 | 2009 | 2008 | |||||||||||
|
(Thousands of
|
||||||||||||||
| barrels per day) | ||||||||||||||
|
Crude
|
500 | 78.0% | 80.3% | 88.2% | ||||||||||
|
Fluid catalytic cracker
|
150 | 66.5% | 70.2% | 72.7% | ||||||||||
|
Coker
|
58 | 78.3% | 81.6% | 92.4% | ||||||||||
In January 2011, HOVENSA announced plans to shut down certain
older and smaller processing units on the west side of its
refinery, which will reduce the refinery’s crude oil
distillation capacity from 500,000 to 350,000 barrels per
day, with no impact on the capacity of its coker or FCC unit.
This reconfiguration, which is expected to be completed in the
first quarter of 2011, is being undertaken to improve
efficiency, reliability and competitiveness. In 2010, the
Corporation recorded an impairment charge related to its
investment in HOVENSA. For discussion of the impairment charge,
see Note 4, Refining Joint Venture in the notes to the
financial statements on page 59.
The delayed coker unit permits HOVENSA to run lower-cost heavy
crude oil. HOVENSA has long-term supply contracts with PDVSA to
purchase 115,000 barrels per day of Venezuelan Merey heavy
crude oil and 155,000 barrels per day of Venezuelan Mesa
medium gravity crude oil. 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 390,000 barrels per
day in 2010 compared with 402,000 barrels per day in 2009
and 441,000 barrels per day in 2008. The 2010 and 2009
utilization rates for HOVENSA reflect weaker refining margins,
higher fuel costs and planned and unplanned maintenance. During
the first quarter of 2010, the fluid catalytic cracking unit at
HOVENSA was shut down for a scheduled turnaround. The 2008
utilization rates reflect a refinery wide shut down for
Hurricane Omar.
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
10
Table of Contents
gas oil, operated at a rate of approximately 55,000 barrels
per day in 2010 compared with 63,000 barrels per day in
2009 and 64,000 barrels per day in 2008. Substantially all
of Port Reading’s production is gasoline and heating oil.
During 2010, the Port Reading refining facility was shutdown for
41 days for a scheduled turnaround.
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 1,362
HESS
®
gasoline stations at December 31, 2010, 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:
| 2010* | 2009* | 2008* | ||||||||||
|
Refined Product sales (thousands of barrels per day)
|
||||||||||||
|
Gasoline
|
242 | 236 | 234 | |||||||||
|
Distillates
|
120 | 134 | 143 | |||||||||
|
Residuals
|
69 | 67 | 56 | |||||||||
|
Other
|
40 | 36 | 39 | |||||||||
|
Total refined product sales
|
471 | 473 | 472 | |||||||||
|
Natural gas (thousands of mcf per day)
|
2,016 | 2,010 | 1,955 | |||||||||
|
Electricity (megawatts round the clock)
|
4,140 | 4,306 | 3,152 | |||||||||
| * | Of total refined products sold, approximately 41%, 45% and 50% was obtained from HOVENSA and Port Reading in 2010, 2009 and 2008, respectively. 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 established to build and operate a
512-megawatt natural gas fueled electric generating station in
Bayonne, New Jersey. The joint venture plans to sell electricity
into the New York City market by a direct connection with the
Con Edison Gowanus substation. Construction of the facility
began in mid-2010 and operations are expected to commence in
2012.
The Corporation has a 50% voting interest in a consolidated
partnership that trades energy commodities and derivatives. The
Corporation also takes energy commodity and derivative trading
positions for its own account.
The Corporation is pursuing opportunities for LNG import
terminals in Shannon, Ireland and on the East Coast of the
United States. In addition, a subsidiary of the Corporation is
exploring the development of fuel cell and hydrogen reforming
technologies.
For additional financial information by segment see
Note 18, 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.
11
Table of Contents
Other
Items
Gulf of Mexico Update:
In April 2010, an
accident occurred on the Transocean Deepwater Horizon drilling
rig at the BP p.l.c. (BP) operated Macondo prospect in the Gulf
of Mexico, resulting in loss of life, the sinking of the rig and
a significant crude oil spill. The Corporation was not a
participant in the well. As a result of the accident, a
temporary drilling moratorium was imposed in the Gulf of Mexico.
In October 2010, the drilling moratorium was lifted by the
United States Department of the Interior’s Bureau of Ocean
Energy Management, Regulation and Enforcement (BOEMRE) provided
operators complied with all rules and requirements, including a
series of new drilling and safety rules issued by BOEMRE. The
Corporation is currently evaluating the impact of these new
requirements on its activities in the Gulf of Mexico, as well as
seeking approvals for plans and permits submitted in connection
with planned activities. However, the new regulatory environment
is expected to result in a longer permitting process and higher
costs.
The moratorium impacted development drilling at the Shenzi
Field, in which the Corporation has a 28% interest. A production
well that was being drilled was suspended and the drilling of a
second production well that was planned for 2010 was postponed.
The Corporation estimates that these delays reduced 2010
production by approximately 2,000 barrels of oil equivalent per
day (boepd) and will likely reduce 2011 production by
approximately 4,000 boepd. In 2010, the Corporation’s only
operated drilling rig in the Gulf of Mexico, the Stena Forth,
left the Pony project on Green Canyon 469 as part of a
preexisting agreement for a one well farm-out of the rig to
another operator.
In January 2011, the BOEMRE announced that supplementary
environmental reviews will not be required of 13 companies
to resume work on the 16 wells that were in progress when
the moratorium took effect, including the aforementioned
suspended Shenzi and Pony wells. However, these projects must
comply with the new safety rules and regulations before work can
resume. As a result, the Corporation does not anticipate that it
will be able to re-commence these operations before the second
half of 2011.
Additionally, the Corporation has filed Suspension of Operations
(SOO) applications with the BOEMRE for several exploration block
licenses in the Gulf of Mexico that are due to expire in 2011
and may file additional applications as deemed necessary. These
SOO applications seek approval for extension of the lease
expiration terms due to circumstances outside the control of the
Corporation that have delayed activities required to hold the
licenses.
Remediation Plans and Procedures:
The
Corporation has in place a series of asset-specific emergency
response and continuity plans which detail procedures for rapid
and effective emergency response and environmental mitigation
activities for its global offshore operations. These plans are
maintained, reviewed and updated annually to ensure their
accuracy and suitability.
Where appropriate, plans are reviewed and approved by the
relevant host government authorities on a periodic basis. The
Corporation has a current oil spill response plan for its Gulf
of Mexico operations that has been approved by the BOEMRE. This
plan sets forth expectations for response training, drills and
capabilities and the strategies, procedures and methods that
will be employed in the event of a spill covering the following
topics: spill response organization, incident command post,
communications and notifications, spill detection and assessment
(including worst case discharge scenarios), identification and
protection of environmental resources, strategic response
planning, mobilization and deployment of spill response
equipment and personnel, oil and debris removal and disposal,
the use of dispersants and chemical and biological agents,
in-situ burning of oil, wildlife rehabilitation and
documentation requirements.
Responder training and drills are routinely held worldwide to
assess and continually improve the effectiveness of the
Corporation’s plans. The Corporation’s contractors,
service providers, representatives from government agencies and,
where applicable, joint venture partners participate in the
drills to ensure that emergency procedures are comprehensive and
can be effectively implemented.
To complement internal capabilities, the Corporation maintains
membership contracts with oil spill response organizations to
provide coverage for its global drilling and production
operations. These organizations are Clean Gulf Associates,
National Response Corporation (NRC) and Oil Spill Response
(OSR). Clean Gulf Associates is a regional spill response
organization for the Gulf of Mexico; NRC and OSR are global
response corporations and are available to assist the
Corporation when needed anywhere in the world. In addition to
owning response assets in
12
Table of Contents
their own right, these organizations maintain business
relationships that provide immediate access to additional
critical response support services if required. These owned
response assets include nearly 300 recovery and storage vessels
and barges, more than 250 skimmers, over 300,000 feet of
boom, and significant quantities of dispersants and other
ancillary equipment, including aircraft. If the Corporation were
to request these organizations to obtain additional critical
response support services, it would provide the funding for such
services and seek reimbursement under its insurance coverages
described below. In certain circumstances, the Corporation
pursues and enters into mutual aid agreements with other
companies and government cooperatives to receive and provide oil
spill response equipment and personnel support. It also has
representation on the Executive Committee of Clean Gulf
Associates and the Board of Directors of OSR, maintaining close
associations with these organizations.
In light of the recent events in the Gulf of Mexico, the
Corporation is participating in a number of industry-wide task
forces that are studying better ways to assess the risk of and
prevent offshore incidents, access and control blowouts in
subsea environments, and improve containment and recovery
methods. The task forces are working closely with the oil and
gas industry and international government agencies to implement
improvements and increase the effectiveness of oil spill
prevention, preparedness, response and recovery processes.
Insurance Coverage and Indemnification:
The
Corporation maintains insurance coverage that includes coverage
for physical damage to its property, third party liability,
workers’ compensation and employers’ liability,
general liability, sudden and accidental pollution, and other
coverage. This insurance coverage is subject to deductibles,
exclusions and limitations and there is no assurance that such
coverage will adequately protect the Corporation against
liability from all potential consequences and damages.
The amount of insurance covering physical damage to the
Corporation’s property and liability related to negative
environmental effects resulting from a sudden and accidental
pollution event, excluding windstorm coverage in the Gulf of
Mexico where it is self insured, varies by asset, based on the
asset’s estimated replacement value or the estimated
maximum loss. In the case of a catastrophic event, first party
coverage consists of two tiers of insurance. The first
$250 million of coverage is provided through an industry
mutual insurance group. Above this $250 million threshold,
insurance is carried which ranges in value to over
$1.9 billion in total, depending on the asset coverage
level, as described above. Additionally, the Corporation carries
insurance which provides third party coverage for general
liability, and sudden and accidental pollution, up to
$995 million.
Other insurance policies provide coverage for, among other
things: charterer’s legal liability, in the amount of
$500 million per occurrence and aircraft liability, in the
amount of $300 million per occurrence.
The Corporation’s insurance policies renew at various dates
each year. Future insurance coverage for the industry could
increase in cost and may include higher deductibles or
retentions, or additional exclusions or limitations. In
addition, some forms of insurance may become unavailable in the
future or unavailable on terms that are deemed economically
acceptable.
Generally, the Corporation’s drilling contracts (and most
of its other offshore services contracts) provide for a mutual
hold harmless indemnity structure whereby each party to the
contract (the Corporation and Contractor) indemnifies the other
party for injuries or damages to their personnel and property
regardless of fault. Variations include indemnity exclusions to
the extent a claim is attributable to the gross negligence
and/or
willful misconduct of a party. Third-party claims, on the other
hand, are generally allocated on a fault basis.
The Corporation is customarily responsible for, and indemnifies
the Contractor against, all claims, including those from
third-parties, to the extent attributable to pollution or
contamination by substances originating from its reservoirs or
other property (regardless of fault, including gross negligence
and willful misconduct) and the Contractor is responsible for
and indemnifies the Corporation for all claims attributable to
pollution emanating from the Contractor’s property.
Additionally, the Corporation is generally liable for all of its
own losses and most third-party claims associated with
catastrophic losses such as blowouts, cratering and loss of
hole, regardless of cause, although exceptions for losses
attributable to gross negligence
and/or
willful misconduct do exist. Lastly, many offshore services
contracts include overall limitations of the Contractor’s
liability equal to the value of the contract or a fixed amount,
whichever is greater.
Under a standard joint operating agreement (JOA), each party is
liable for all claims arising under the JOA, not covered by or
in excess of insurance carried by the JOA, to the extent of its
participating interest (operator or non-
13
Table of Contents
operator). Variations include indemnity exclusions where the
claim is based upon the gross negligence
and/or
willful misconduct of a party in which case such party is solely
liable.
Environmental:
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 results of operations. The Corporation
spent $13 million in 2010 for environmental remediation.
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.
Number of Employees:
The number of persons
employed by the Corporation at year-end was approximately 13,800
in 2010 and 13,300 in 2009.
Other:
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. The contents of the Corporation’s
website are not incorporated by reference in this report. 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.
Our business and operating results are highly dependent on
the market prices of crude oil, natural gas, refined petroleum
products and electricity, which can be very
volatile.
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, refined petroleum products and electricity,
which are influenced by numerous factors beyond our control.
Historically these prices have been very volatile. The major
foreign oil producing countries, including members of the
Organization of Petroleum Exporting Countries (OPEC), exert
considerable influence over the supply and price of crude oil
and refined petroleum products. Their ability or inability to
agree on a common policy on rates of production and other
matters has a significant impact on the oil markets. The
commodities trading markets as well as other supply and demand
factors may also influence the selling prices of crude oil,
natural gas, refined petroleum products and electricity. 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.
If we fail to successfully increase our reserves, our future
crude oil and natural gas production will be adversely
impacted.
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 production and reserves, including
proved undeveloped 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
14
Table of Contents
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.
There are inherent uncertainties in estimating quantities of
proved reserves and discounted future net cash flow, and actual
quantities may be lower than estimated.
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 of our proved reserves and the related future net
revenues. 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.
We are subject to changing laws and regulations and other
governmental actions that can significantly and adversely affect
our business.
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 and export
regulations, limitations on access to exploration and
development opportunities, as well as other political
developments may affect our operations. We also 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. As a result of the accident in April 2010 at the
BP-operated Macondo prospect in the Gulf of Mexico (in which the
Corporation was not a participant) and the ensuing significant
oil spill, a temporary drilling moratorium was imposed in the
Gulf of Mexico. While this moratorium has since been lifted,
significant new regulations have been imposed and further
legislation and regulations may be proposed, including an
increase in the potential liability in the event of an oil
spill. Uncertainty continues to exist as to the conditions under
which future drilling in the Gulf of Mexico will occur. However,
the new regulatory environment is expected to result in a longer
permitting process and higher costs.
Political instability in areas where we operate can adversely
affect our business.
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. Current political unrest in North Africa and the
Middle East may affect our operations in these areas as well as
oil and gas markets generally. The threat of terrorism around
the world also poses additional risks to the operations of the
oil and gas industry.
Our oil and gas operations are subject to environmental risks
and environmental laws and regulations that can result in
significant costs and liabilities.
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. For example, the accident at the
BP-operated Macondo prospect in April 2010 resulted in a
significant release of crude oil which caused extensive
environmental and economic 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.
Concerns have been raised in certain jurisdictions where we have
operations concerning the safety and environmental impact of the
drilling and development of unconventional oil and gas
resources, particularly using the process of hydraulic
fracturing. While we believe that these operations can be
conducted safely and with minimal impact on the environment,
regulatory bodies are responding to these concerns and may
impose temporary moratoriums and new regulations on such
drilling operations that would likely have the effect of
delaying and increasing the cost of such operations.
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Concerns about climate change may result in significant
operational changes and expenditures and reduced demand for our
products.
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, which may
result in 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.
Our industry is highly competitive and many of our
competitors are larger and have greater resources than
us.
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, resulting in increased
capital and operating costs.
Catastrophic events, whether naturally occurring or man-made,
may materially affect our operations and financial
conditions.
Our oil and gas operations are
subject to unforeseen occurrences which have affected us from
time to time and which may damage or destroy assets, interrupt
operations and have other significant adverse effects. Examples
of catastrophic risks include hurricanes, fires, explosions and
blowouts, such as the accident at the Macondo prospect operated
by BP in the Gulf of Mexico. Although we maintain a level of
insurance coverage consistent with industry practices against
property and casualty losses, there can be no assurance that
such insurance will adequately protect the Corporation against
liability from all potential consequences and damages. Moreover,
some forms of insurance may be unavailable in the future or be
available only on terms that are deemed economically
unacceptable.
| 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
2010, additional cases were settled, and three new cases were
filed. The six unresolved cases consist of five 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
16
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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. In January 2011, HOVENSA signed a Consent Decree with
EPA to resolve its claims. Under the terms of the Consent
Decree, HOVENSA will pay a penalty of approximately
$5 million and spend approximately $700 million over
the next 10 years to install equipment and implement
additional operating procedures at the HOVENSA refinery to
reduce emissions. In addition, the Consent Decree requires
HOVENSA to spend approximately $5 million to fund an
environmental project to be determined at a later date by the
Virgin Islands and $500,000 to assist the Virgin Islands Water
and Power Authority with monitoring. The Consent Decree has been
lodged with the United States District Court for the Virgin
Islands and approval is pending. In addition, substantial
progress has been made towards resolving this matter for the
Port Reading refining facility, which is not expected to have a
material adverse impact on the Corporation’s financial
position or results of operations.
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. This matter is resolved by the Consent
Decree discussed above, provided that the Consent Decree is
entered by the court.
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. This matter is resolved by the
Consent Decree discussed above, provided that the Consent Decree
is entered by the court.
On December 16, 2010, the Virgin Islands Department of
Planning and Natural Resources commenced four separate
enforcement actions against HOVENSA by issuance of documents
titled “Notice Of Violation, Order For Corrective Action,
Notice Of Assessment Of Civil Penalty, Notice Of Opportunity For
Hearing” (the “NOVs”). The NOVs assert violations
of Virgin Islands Air Pollution Control laws and regulations
arising out of air release incidents at the HOVENSA refinery in
2009 and 2010 and propose total penalties of $1,355,000. HOVENSA
intends to vigorously defend this matter.
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
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 a
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
17
Table of Contents
from releases of hazardous substances from the HOVENSA Refinery,
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 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. The Corporation cannot predict
with certainty if, how or when such proceedings will be resolved
or what the eventual relief, if any, may be, particularly for
proceedings that are in their early stages of development or
where plaintiffs seek indeterminate damages. Numerous issues may
need to be resolved, including through potentially lengthy
discovery and determination of important factual matters before
a loss or range of loss can be reasonably estimated for any
proceeding. Subject to the foregoing, in management’s
opinion, based upon currently known facts and circumstances, the
outcome of such proceedings will not have a material adverse
effect on the financial condition of the Corporation, although
the outcome of such proceedings could be material to the
Corporation’s results of operations and cash flows for a
particular period depending on, among other things, the level of
the Corporation’s net income for such period.
18
Table of Contents
PART II
| 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:
| 2010 | 2009 | |||||||||||||||||
| Quarter Ended | High | Low | High | Low | ||||||||||||||
|
March 31
|
$ | 66.49 | $ | 55.89 | $ | 66.84 | $ | 49.28 | ||||||||||
|
June 30
|
66.22 | 48.70 | 69.74 | 49.72 | ||||||||||||||
|
September 30
|
59.79 | 48.71 | 57.83 | 46.33 | ||||||||||||||
|
December 31
|
76.98 | 59.23 | 62.18 | 51.41 | ||||||||||||||
Performance
Graph
Set forth below is a line graph comparing the five-year
shareholder return on a $100 investment in the
Corporation’s common stock assuming reinvestment of
dividends, against the cumulative total returns for the
following indexes:
| • | 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, 2010, there were 5,791 stockholders (based
on number of holders of record) who owned a total of
337,680,780 shares of common stock.
Dividends
Cash dividends on common stock totaled $0.40 per share ($0.10
per quarter) during 2010, 2009 and 2008.
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Table of Contents
Equity
Compensation Plans
Following is information on the Registrant’s equity
compensation plans at December 31, 2010:
|
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
|
13,420,000 | $ | 55.73 | 11,507,000 | * | |||||||||
|
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 10, Share-Based Compensation, in the notes to the
financial statements for further discussion of the
Corporation’s equity compensation plans.
20
Table of Contents
| Item 6. | Selected Financial Data |
A five-year summary of selected financial data follows*:
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (Millions of dollars, except per share amounts) | ||||||||||||||||||||
|
Sales and other operating revenues
|
||||||||||||||||||||
|
Crude oil and natural gas liquids
|
$ | 7,235 | $ | 5,665 | $ | 7,764 | $ | 6,303 | $ | 5,307 | ||||||||||
|
Natural gas (including sales of purchased gas)
|
5,723 | 5,894 | 8,800 | 6,877 | 6,826 | |||||||||||||||
|
Refined petroleum products
|
16,103 | 12,931 | 19,765 | 14,741 | 13,339 | |||||||||||||||
|
Electricity
|
3,165 | 3,408 | 3,451 | 2,322 | 1,072 | |||||||||||||||
|
Convenience store sales and other operating revenues
|
1,636 | 1,716 | 1,354 | 1,484 | 1,632 | |||||||||||||||
|
Total
|
$ | 33,862 | $ | 29,614 | $ | 41,134 | $ | 31,727 | $ | 28,176 | ||||||||||
|
Net income attributable to Hess Corporation
|
$ | 2,125 | (a) | $ | 740 | (b) | $ | 2,360 | (c) | $ | 1,832 | (d) | $ | 1,920 | (e) | |||||
|
Less: preferred stock dividends
|
— | — | — | — | 44 | |||||||||||||||
|
Net income applicable to Hess Corporation common shareholders
|
$ | 2,125 | $ | 740 | $ | 2,360 | $ | 1,832 | $ | 1,876 | ||||||||||
|
Earnings per share
|
||||||||||||||||||||
|
Basic
|
$ | 6.52 | $ | 2.28 | $ | 7.35 | $ | 5.86 | $ | 6.75 | ||||||||||
|
Diluted
|
$ | 6.47 | $ | 2.27 | $ | 7.24 | $ | 5.74 | $ | 6.08 | ||||||||||
|
Total assets
|
$ | 35,396 | $ | 29,465 | $ | 28,589 | $ | 26,131 | $ | 22,442 | ||||||||||
|
Total debt
|
5,583 | 4,467 | 3,955 | 3,980 | 3,772 | |||||||||||||||
|
Total equity
|
16,809 | 13,528 | 12,391 | 10,000 | 8,376 | |||||||||||||||
|
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. | |
| (a) | Includes after-tax income of $1,130 million relating to gains on asset dispositions, partially offset by charges totaling $694 million for an asset impairment, an impairment of the Corporation’s equity investment in HOVENSA L.L.C., dry hole expense and premiums on repurchases of fixed-rate notes. | |
| (b) | Includes after-tax expenses totaling $104 million relating to repurchases of fixed-rate notes, retirement benefits, employee severance costs and asset impairments, partially offset by after-tax income totaling $101 million principally relating to the resolution of a United States royalty dispute. | |
| (c) | Includes after-tax expenses totaling $26 million primarily relating to asset impairments and hurricanes in the Gulf of Mexico. | |
| (d) | Includes net after-tax expenses of $75 million primarily relating to asset impairments, estimated production imbalance settlements and a charge for MTBE litigation, partially offset by income from LIFO inventory liquidations and gains from asset sales. | |
| (e) | 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. |
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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 2010 was $2,125 million compared with
$740 million in 2009 and $2,360 million in 2008.
Diluted earnings per share were $6.47 in 2010 compared with
$2.27 in 2009 and $7.24 in 2008. A table of items affecting
comparability between periods is shown on page 25.
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 1,537 million barrels of oil
equivalent (boe) at December 31, 2010 compared with
1,437 million boe at December 31, 2009 and
1,432 million boe at December 31, 2008.
E&P earnings were $2,736 million in 2010,
$1,042 million in 2009 and $2,423 million in 2008.
Average realized crude oil selling prices were $66.20 per barrel
in 2010, $51.62 in 2009, and $82.04 in 2008, including the
impact of hedging. Production averaged 418,000 barrels of
oil equivalent per day (boepd) in 2010, an increase of 10,000
boepd or 2.5% from 2009. Production averaged 408,000 boepd in
2009, an increase of 27,000 boepd or 7% from 381,000 boepd in
2008. The Corporation estimates that total worldwide production
will average between 415,000 and 425,000 boepd in 2011.
The following is an update of significant E&P activities
during 2010:
| • | In December, the Corporation acquired approximately 167,000 net acres in the Bakken oil shale play (Bakken) in North Dakota for $1,075 million in cash from TRZ Energy, LLC. The Corporation also completed the acquisition of American Oil & Gas Inc. (American Oil & Gas) through the issuance of approximately 8.6 million shares of the Corporation’s stock, which further increased its acreage position in the Bakken by approximately 85,000 net acres. After these acquisitions, the Corporation holds more than 900,000 net acres in the Bakken. The properties acquired are located near the Corporation’s existing acreage. | |
| • | In September, the Corporation completed the exchange of its interests in Gabon and the Clair Field in the United Kingdom for additional interests in the Valhall and Hod fields of 28% and 25%, respectively. This non-monetary exchange, which was recorded at fair value, resulted in a pre-tax gain of $1,150 million ($1,072 million after income taxes). The Corporation also completed the acquisition of an additional 8% interest in the Valhall Field and 13% interest in the Hod Field for $507 million in cash. As a result of these transactions, the Corporation’s interests in the Valhall and Hod fields increased to 64% and 63%, respectively. | |
| • | In the fourth quarter, the Corporation completed the acquisition of an additional 20% interest in the Tubular Bells oil and gas field in the Gulf of Mexico for approximately $40 million. The Corporation now has a 40% working interest and is operator of the field. | |
| • | In January, the Corporation completed the sale of its interest in the Jambi Merang natural gas development project in Indonesia (Hess 25%) for cash proceeds of $183 million. The transaction resulted in a gain of $58 million. | |
| • | In March, the Corporation agreed to the sale of its interests in a package of natural gas production and transportation assets in the United Kingdom North Sea. The package includes the Corporation’s interests in the Easington Catchment Area (Hess 30%), the Bacton Area (Hess 23%), the Everest Field (Hess 19%), the Lomond Field (Hess 17%) and the Central Area Transmission System (CATS) pipeline (Hess 18%). In February 2011, the Corporation completed the sale of the producing assets for approximately $350 million, |
22
Table of Contents
| after closing adjustments. The sale of the Corporation’s interest in the CATS pipeline is expected to close in the second quarter of 2011. |
| • | In September, the Corporation recorded an impairment charge and dry hole expense totaling $554 million before income taxes ($347 million after income taxes) to reduce the carrying value of unproved property and suspended well costs relating to its 55% interest in the West Mediterranean Block 1 Concession (West Med Block), located offshore Egypt. | |
| • | In the Carnarvon basin offshore Western Australia, the Corporation drilled 4 exploration wells in 2010 on WA-390-P Block (Hess 100%). The Corporation has drilled all 16 commitment wells on the block, 13 of which were natural gas discoveries. In the fourth quarter of 2010, the Corporation commenced an appraisal program that includes further drilling and flow testing certain wells. | |
| • | On the Pony project in Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico, the Corporation has signed a non-binding agreement in principle with the owners on the adjacent Green Canyon Block 512 that outlines a proposal to jointly develop the Pony and Knotty Head fields. The Corporation also spud and subsequently suspended an appraisal well on the Pony prospect in 2010. The Corporation is planning to resume drilling of the Pony appraisal well in 2011 contingent upon receipt of necessary drilling permits. | |
| • | In November, the third exploration well was spud on Block BM-S-22 (Hess 40%) offshore Brazil which encountered noncommercial quantities of hydrocarbons. As a result, dry hole expenses totaling $111 million ($72 million after-tax) were recorded relating to this well and the previously suspended Azulão well, which was drilled in 2009. |
Gulf of Mexico Update:
In April 2010,
an accident occurred on the Transocean Deepwater Horizon
drilling rig at the BP p.l.c. (BP) operated Macondo prospect in
the Gulf of Mexico, resulting in loss of life, the sinking of
the rig and a significant crude oil spill. The Corporation was
not a participant in the well. As a result of the accident, a
temporary drilling moratorium was imposed in the Gulf of Mexico.
In October 2010, the drilling moratorium was lifted by the
United States Department of the Interior’s Bureau of Ocean
Energy Management, Regulation and Enforcement (BOEMRE) provided
operators complied with all rules and requirements, including a
series of new drilling and safety rules issued by BOEMRE. The
Corporation is currently evaluating the impact of these new
requirements on its activities in the Gulf of Mexico, as well as
seeking approvals for plans and permits submitted in connection
with planned activities. However, the new regulatory environment
is expected to result in a longer permitting process and higher
costs.
The moratorium impacted development drilling at the Shenzi
Field, in which the Corporation has a 28% interest. A production
well that was being drilled was suspended and the drilling of a
second production well that was planned for 2010 was postponed.
The Corporation estimates that these delays reduced 2010
production by approximately 2,000 boepd and will likely reduce
2011 production by approximately 4,000 boepd. In 2010, the
Corporation’s only operated drilling rig in the Gulf of
Mexico, the Stena Forth, left the Pony project on Green Canyon
469 as part of a preexisting agreement for a one well farm-out
of the rig to another operator.
In January 2011, the BOEMRE announced that supplementary
environmental reviews will not be required of 13 companies
to resume work on the 16 wells that were in progress when
the moratorium took effect, including the aforementioned
suspended Shenzi and Pony wells. However, these projects must
comply with the new safety rules and regulations before work can
resume. As a result, the Corporation does not anticipate that it
will be able to re-commence these operations before the second
half of 2011.
Additionally, the Corporation has filed Suspension of Operations
(SOO) applications with the BOEMRE for several exploration block
licenses in the Gulf of Mexico that are due to expire in 2011
and may file additional applications as deemed necessary. These
SOO applications seek approval for extension of the lease
expiration terms due to circumstances outside the control of the
Corporation that have delayed activities required to hold the
licenses.
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Table of Contents
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 earnings (losses) were $(231) million in
2010, $127 million in 2009 and $277 million in 2008.
Refining operations generated losses of $445 million in
2010 and $87 million in 2009 and income of $73 million
in 2008. Refining results for 2010 include an after-tax
impairment charge of $289 million ($300 million
pre-tax) to reduce the carrying value of the Corporation’s
investment in HOVENSA L.L.C. to the estimated fair value. The
refining results in 2010 and 2009 also reflect weak refining
margins and lower volumes. Marketing earnings were
$215 million in 2010, $168 million in 2009 and
$240 million in 2008.
Liquidity
and Capital and Exploratory Expenditures
Net cash provided by operating activities was
$4,530 million in 2010, $3,046 million in 2009 and
$4,688 million in 2008, principally reflecting fluctuations
in earnings. At December 31, 2010, cash and cash
equivalents totaled $1,608 million compared with
$1,362 million at December 31, 2009. Total debt was
$5,583 million at December 31, 2010 compared with
$4,467 million at December 31, 2009. In August 2010,
the Corporation issued $1,250 million of 30 year
fixed-rate notes with a coupon of 5.6% that are scheduled to
mature in 2041. The proceeds were used for the acquisition of
additional acreage in the Bakken and additional interests in the
Valhall and Hod fields. In January 2010, the Corporation
completed the repurchase of the remaining $116 million of
notes that were scheduled to mature in 2011. The
Corporation’s debt to capitalization ratio at
December 31, 2010 was 24.9% compared with 24.8% at the end
of 2009.
Capital and exploratory expenditures were as follows for the
years ended December 31:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Exploration and Production
|
||||||||
|
United States
|
$ | 2,935 | $ | 1,200 | ||||
|
International
|
2,822 | 1,927 | ||||||
|
Total Exploration and Production
|
5,757 | 3,127 | ||||||
|
Marketing, Refining and Corporate
|
98 | 118 | ||||||
|
Total capital and exploratory expenditures
|
$ | 5,855 | $ | 3,245 | ||||
|
Exploration expenses charged to income included above:
|
||||||||
|
United States
|
$ | 154 | $ | 144 | ||||
|
International
|
209 | 183 | ||||||
|
Total exploration expenses charged to income included above
|
$ | 363 | $ | 327 | ||||
The Corporation anticipates investing $5.6 billion in
capital and exploratory expenditures in 2011, substantially all
of which relates to E&P operations.
Consolidated
Results of Operations
The after-tax results by major operating activity are summarized
below:
| 2010 | 2009 | 2008 | ||||||||||
|
(Millions of dollars,
|
||||||||||||
| except per share data) | ||||||||||||
|
Exploration and Production
|
$ | 2,736 | $ | 1,042 | $ | 2,423 | ||||||
|
Marketing and Refining
|
(231 | ) | 127 | 277 | ||||||||
|
Corporate
|
(159 | ) | (205 | ) | (173 | ) | ||||||
|
Interest expense
|
(221 | ) | (224 | ) | (167 | ) | ||||||
|
Net income attributable to Hess Corporation
|
$ | 2,125 | $ | 740 | $ | 2,360 | ||||||
|
Net income per share — diluted
|
$ | 6.47 | $ | 2.27 | $ | 7.24 | ||||||
24
Table of Contents
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 28 through 31.
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Exploration and Production
|
$ | 732 | $ | 45 | $ | (26 | ) | |||||
|
Marketing and Refining
|
(289 | ) | 12 | — | ||||||||
|
Corporate
|
(7 | ) | (60 | ) | — | |||||||
| $ | 436 | $ | (3 | ) | $ | (26 | ) | |||||
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:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Sales and other operating revenues*
|
$ | 8,744 | $ | 6,835 | $ | 9,806 | ||||||
|
Other, net
|
1,233 | 207 | (167 | ) | ||||||||
|
Total revenues and non operating income
|
9,977 | 7,042 | 9,639 | |||||||||
|
Costs and expenses
|
||||||||||||
|
Production expenses, including related taxes
|
1,924 | 1,805 | 1,872 | |||||||||
|
Exploration expenses, including dry holes and lease impairment
|
865 | 829 | 725 | |||||||||
|
General, administrative and other expenses
|
281 | 255 | 302 | |||||||||
|
Depreciation, depletion and amortization
|
2,222 | 2,113 | 1,922 | |||||||||
|
Asset impairments
|
532 | 54 | 30 | |||||||||
|
Total costs and expenses
|
5,824 | 5,056 | 4,851 | |||||||||
|
Results of operations before income taxes
|
4,153 | 1,986 | 4,788 | |||||||||
|
Provision for income taxes
|
1,417 | 944 | 2,365 | |||||||||
|
Results of operations attributable to Hess Corporation
|
$ | 2,736 | $ | 1,042 | $ | 2,423 | ||||||
| * | Amounts differ from E&P operating revenues in Note 18, Segment Information, primarily due to the exclusion of sales of hydrocarbons purchased from third parties. |
After considering the E&P items in the table on
page 28, the remaining changes in E&P earnings are
primarily attributable to changes in selling prices, production
and sales volumes, operating costs, exploration expenses,
foreign exchange, and income taxes, as discussed below.
Selling prices:
Higher average selling
prices increased E&P revenues by approximately
$1,775 million in 2010 compared with 2009. Lower average
selling prices reduced E&P revenues by approximately
$4,000 million in 2009 compared with 2008.
25
Table of Contents
The Corporation’s average selling prices were as follows:
| 2010 | 2009 | 2008 | ||||||||||
|
Crude oil-per barrel (including hedging)
|
||||||||||||
|
United States
|
$ | 75.02 | $ | 60.67 | $ | 96.82 | ||||||
|
Europe
|
58.11 | 47.02 | 78.75 | |||||||||
|
Africa
|
65.02 | 48.91 | 78.72 | |||||||||
|
Asia
|
79.23 | 63.01 | 97.07 | |||||||||
|
Worldwide
|
66.20 | 51.62 | 82.04 | |||||||||
|
Crude oil-per barrel (excluding hedging)
|
||||||||||||
|
United States
|
$ | 75.02 | $ | 60.67 | $ | 96.82 | ||||||
|
Europe
|
58.11 | 47.02 | 78.75 | |||||||||
|
Africa
|
78.31 | 60.79 | 93.57 | |||||||||
|
Asia
|
79.23 | 63.01 | 97.07 | |||||||||
|
Worldwide
|
71.40 | 56.74 | 89.23 | |||||||||
|
Natural gas liquids-per barrel
|
||||||||||||
|
United States
|
$ | 47.92 | $ | 36.57 | $ | 64.98 | ||||||
|
Europe
|
59.23 | 43.23 | 74.63 | |||||||||
|
Asia
|
63.50 | 46.48 | — | |||||||||
|
Worldwide
|
50.49 | 38.47 | 67.61 | |||||||||
|
Natural gas-per mcf (including hedging)
|
||||||||||||
|
United States
|
$ | 3.70 | $ | 3.36 | $ | 8.61 | ||||||
|
Europe
|
6.23 | 5.15 | 9.44 | |||||||||
|
Asia and other
|
5.93 | 5.06 | 5.24 | |||||||||
|
Worldwide
|
5.63 | 4.85 | 7.17 | |||||||||
|
Natural gas-per mcf (excluding hedging)
|
||||||||||||
|
United States
|
$ | 3.70 | $ | 3.36 | $ | 8.61 | ||||||
|
Europe
|
6.23 | 5.15 | 9.79 | |||||||||
|
Asia and other
|
5.93 | 5.06 | 5.24 | |||||||||
|
Worldwide
|
5.63 | 4.85 | 7.30 | |||||||||
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 $330 million in 2011
and 2012. Crude oil hedges reduced E&P earnings by
$338 million ($533 million before income taxes) in
2010 and $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.
Production and sales volumes:
The
Corporation’s crude oil and natural gas production was
418,000 boepd in 2010 compared with 408,000 boepd in 2009 and
381,000 boepd in 2008. Approximately 73% in 2010, 72% in 2009
and 70% in 2008 of the Corporation’s production was from
crude oil and natural gas liquids. The Corporation currently
estimates that its 2011 production will average between 415,000
and 425,000 boepd, after a reduction of approximately 4,000
boepd due to drilling delays at the Shenzi Field in the Gulf of
Mexico as well as the effect of the sale in February 2011 of
natural gas producing assets in the United Kingdom North Sea.
26
Table of Contents
The Corporation’s net daily worldwide production was as
follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In thousands) | ||||||||||||
|
Crude oil (barrels per day)
|
||||||||||||
|
United States
|
75 | 60 | 32 | |||||||||
|
Europe
|
88 | 83 | 83 | |||||||||
|
Africa
|
113 | 120 | 124 | |||||||||
|
Asia
|
13 | 16 | 13 | |||||||||
|
Total
|
289 | 279 | 252 | |||||||||
|
Natural gas liquids (barrels per day)
|
||||||||||||
|
United States
|
14 | 11 | 10 | |||||||||
|
Europe
|
3 | 3 | 4 | |||||||||
|
Asia
|
1 | — | — | |||||||||
|
Total
|
18 | 14 | 14 | |||||||||
|
Natural gas (mcf per day)
|
||||||||||||
|
United States
|
108 | 93 | 78 | |||||||||
|
Europe
|
134 | 151 | 255 | |||||||||
|
Asia and other
|
427 | 446 | 356 | |||||||||
|
Total
|
669 | 690 | 689 | |||||||||
|
Barrels of oil equivalent* (barrels per day)
|
418 | 408 | 381 | |||||||||
| * | Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. See the average selling prices in the table above. |
United States:
Crude oil and natural
gas production in the United States was higher in 2010 compared
with 2009, primarily due to production from the Shenzi, Llano,
Conger and Bakken fields. Crude oil and natural gas production
was higher in 2009 compared with 2008, primarily due to new
production from the Shenzi Field and production resuming after
the 2008 hurricanes. Hurricane impacts reduced full year 2008
production by an estimated 7,000 boepd.
Europe:
Crude oil production was higher
in 2010 compared with 2009, due to higher production in Russia
and an increase in Norway following the acquisition of
additional interests in the Valhall and Hod fields, partially
offset by lower production in the United Kingdom North Sea
following the exchange of Clair for additional Norway interests.
Crude oil production was comparable in 2009 and 2008, as higher
production in Russia offset lower production in the United
Kingdom North Sea. Natural gas production was lower in 2010
compared with 2009, primarily due to downtime at certain United
Kingdom gas fields. Natural gas production was lower in 2009
compared with 2008, primarily due to decline and subsequent
cessation of production at the Atlantic and Cromarty fields.
Africa:
Crude oil production decreased
in 2010 compared with 2009 following the exchange of Gabon for
additional interests in the Valhall and Hod fields in Norway in
the third quarter and lower entitlement to Algerian production.
Crude oil production decreased in 2009 compared with 2008,
primarily due to lower production from the Ceiba Field.
Asia and other:
Natural gas production
in 2010 was lower than in 2009, primarily due to downtime at the
Pangkah Field and a temporary shut-in at the Bumi Field in the
Joint Development Area of Malaysia/Thailand (JDA). Natural gas
production in 2009 was higher than in 2008, primarily due to a
full year of Phase 2 sales from JDA. The decrease in crude oil
production in 2010 from 2009 principally reflects changes to the
Corporation’s entitlement to production in Azerbaijan.
27
Table of Contents
Sales volumes:
Higher sales volumes and
other operating revenues increased revenue by approximately
$135 million in 2010 compared with 2009 and
$1,030 million in 2009 compared with 2008.
Operating costs and depreciation, depletion and
amortization:
Cash operating costs,
consisting of production expenses and general and administrative
expenses, increased by $145 million in 2010 compared with
2009 and decreased by $114 million in 2009 compared with
2008. The increase in 2010 compared with 2009 was primarily due
to higher production taxes as a result of higher selling prices.
The decrease in 2009 compared with 2008 was primarily due to
lower production taxes (due to lower realized selling prices),
the cessation of production at several United Kingdom North Sea
fields, the favorable impact of foreign exchange rates and cost
savings initiatives, partially offset by the impact of higher
production volumes.
Depreciation, depletion and amortization charges increased by
$109 million in 2010 and $191 million in 2009,
compared with the corresponding amounts in prior years. The
increases in both 2010 and 2009 were primarily due to higher
production volumes and per barrel costs, reflecting higher
finding and development costs.
Excluding items affecting comparability between periods, cash
operating costs per barrel of oil equivalent were $14.45 in
2010, $13.70 in 2009 and $15.49 in 2008. Cash operating costs in
2011 are estimated to be in the range of $15.00 to $16.00 per
barrel of oil equivalent. Depreciation, depletion and
amortization costs per barrel of oil equivalent were $14.56 in
2010, $14.19 in 2009 and $13.79 in 2008. Depreciation, depletion
and amortization costs for 2011 are estimated to be in the range
of $14.50 to $15.50 per barrel of oil equivalent.
Effective December 31, 2009, the Securities and Exchange
Commission (SEC) issued updated standards for oil and gas
reserve estimation and disclosure. The new rules allow, among
other changes, the use of permitted technology in determining
oil and gas reserve estimates. Since it was not practical to
calculate reserve estimates under both the old and the new
reserve estimation standards, it was 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 applying the new rules increased
income during 2010 by approximately $80 million, after
income taxes, due to lower depreciation, depletion and
amortization expense.
Exploration expenses:
Exploration
expenses increased in 2010 from 2009, primarily due to higher
lease amortization. Exploration expenses increased in 2009
compared to 2008, mainly due to higher dry hole costs and lease
amortization.
Income taxes:
Excluding the impact of
items affecting comparability, the effective income tax rates
for E&P operations were 44% in 2010, 48% in 2009 and 49% in
2008. The effective income tax rate for E&P operations in
2011 is estimated to be in the range of 45% to 49%.
Foreign Exchange:
The after-tax foreign
currency losses were $9 million in 2010, $10 million
in 2009 and $80 million in 2008. 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 | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Gains on asset sales
|
$ | 1,208 | $ | — | $ | — | $ | 1,130 | $ | — | $ | — | ||||||||||||
|
Royalty dispute resolution
|
— | 143 | — | — | 89 | — | ||||||||||||||||||
|
Asset impairments
|
(532 | ) | (54 | ) | (30 | ) | (334 | ) | (26 | ) | (17 | ) | ||||||||||||
|
Dry hole expense
|
(101 | ) | — | — | (64 | ) | — | — | ||||||||||||||||
|
Reductions in carrying values of assets
|
— | (23 | ) | — | — | (18 | ) | — | ||||||||||||||||
|
Hurricane related costs
|
— | — | (15 | ) | — | — | (9 | ) | ||||||||||||||||
| $ | 575 | $ | 66 | $ | (45 | ) | $ | 732 | $ | 45 | $ | (26 | ) | |||||||||||
28
Table of Contents
2010:
The Corporation completed the exchange
of its interests in Gabon and the Clair Field in the
United Kingdom for additional interests of 28% and 25%,
respectively, in the Valhall and Hod fields in Norway. This
non-monetary transaction, which was recorded at fair value,
resulted in a pre-tax gain of $1,150 million
($1,072 million after income taxes). The Corporation also
completed the sale of its interest in the Jambi Merang natural
gas development project in Indonesia for a gain of
$58 million.
The Corporation recorded a charge of $532 million
($334 million after income taxes) to fully impair the
carrying value of its 55% interest in the West Med Block,
located offshore Egypt. This interest was acquired in 2006 and
included four natural gas discoveries and additional exploration
prospects. The Corporation and its partners subsequently
explored and further evaluated the area, made a fifth discovery,
conducted development planning, and held negotiations with the
Egyptian authorities to amend the existing gas sales agreement.
In September 2010, the Corporation and its partners notified the
Egyptian authorities of their decision to cease exploration
activities and to relinquish a significant portion of the block.
As a result, the Corporation fully impaired the carrying value
of its interests in the West Med Block.
The Corporation recorded $101 million ($64 million
after income taxes) of dry hole expenses related to previously
suspended well costs on the West Med Block offshore Egypt and
Block BM-S-22 offshore Brazil, both of which were drilled prior
to 2010.
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
(predecessor to the Bureau of Ocean Energy Management,
Regulation and Enforcement) relating to royalty relief under the
Deep Water Royalty Relief Act of 1995. As a result, the
Corporation recognized after-tax income of $89 million to
reverse all previously recorded royalties covering the periods
from 2003 to 2009. The pre-tax amount of $143 million was
reported in Other, net in the Statement of Consolidated Income.
The Corporation recorded total asset impairment charges of
$54 million ($26 million after income taxes) to reduce
the carrying value of two-short lived fields in the United
Kingdom North Sea.
Pre-tax charges of approximately $25 million
($18 million after income taxes) were recorded to impair
the carrying values of production equipment and to write down
materials inventories in Equatorial Guinea and the United
States. The pre-tax amount of most of the inventory write downs
was reported in Production expenses in the Statement of
Consolidated Income.
2008:
Pre-tax charges of $30 million
($17 million after income taxes) were recorded to impair
the carrying values of mature fields in the United States and
the United Kingdom North Sea.
Pre-tax charges of $15 million ($9 million after
income taxes) were recorded to expense costs associated with
Hurricanes Gustav and Ike in the Gulf of Mexico. The pre-tax
amount of the charges totaling $15 million were reported in
Production expenses in the Statement of Consolidated Income.
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,
exploration expenses, industry cost inflation, changes in
foreign exchange rates and income tax rates, the effects of
weather, political risk, environmental risk and catastrophic
risk. In addition, as a result of the oil spill in 2010 at the
BP operated Macondo prospect in the Gulf of Mexico, there have
been and there may be further changes in laws and regulations
that could impact the Corporation’s future drilling
operations and increase its potential liability in the event of
an oil spill. For a more comprehensive description of the risks
that may affect the Corporation’s E&P business, see
Item 1A. Risk Factors Related to Our Business and
Operations.
Marketing
and Refining
Earnings (losses) from M&R activities amounted to
$(231) million in 2010, $127 million in 2009 and
$277 million in 2008. Excluding the items affecting
comparability reflected in the table on page 25 and
discussed below, the earnings were $58 million,
$115 million and $277 million, respectively.
29
Table of Contents
Refining:
Refining earnings (losses),
which consist of the Corporation’s share of HOVENSA’s
results, Port Reading earnings and results of other
miscellaneous operating activities, were $(445) million in
2010 (including the $289 million after-tax impairment
charge discussed below), $(87) million in 2009 (including a
benefit of $12 million due to an income tax adjustment) and
$73 million in 2008.
In December 2010, the Corporation recorded an impairment charge
of $300 million before income taxes ($289 million
after income taxes) to reduce the carrying value of its equity
investment in HOVENSA, which was recorded in Income (loss) from
equity investment in HOVENSA L.L.C. The investment had been
adversely affected by consecutive annual operating losses
resulting from continued weak refining margins and refinery
utilization, and a fourth quarter 2010 debt rating downgrade. As
a result of a strategic assessment in 2010, HOVENSA decided to
lower crude oil refining capacity from 500,000 to
350,000 barrels per day. The Corporation performed an
impairment analysis and concluded that its investment had
experienced an other than temporary decline in value. For
discussion of the impairment charge, see Note 4, Refining Joint
Venture in the notes to the financial statements on page 59. As
a result of cumulative net operating losses in the last two
years, the Corporation is not recognizing a full income tax
benefit on the impairment charge.
The Corporation’s share of HOVENSA’s results was a
loss of $138 million in 2010 ($222 million before
income taxes) excluding the impairment charge, a loss of
$142 million ($229 million before income taxes) in
2009, and income of $27 million ($44 million before
income taxes) in 2008. These results reflect lower refining
margins and lower sales volumes. The 2010 and 2009 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. During
2010, the fluid catalytic cracking unit at HOVENSA was shut down
for a scheduled turnaround. The Corporation’s share of
HOVENSA’s turnaround expenses was approximately
$20 million after income taxes.
Other after-tax refining results, principally from Port Reading
operations, were a loss of $18 million in 2010 and income
of $43 million in both 2009 and 2008. During 2010, the Port
Reading refining facility was shutdown for 41 days for a
scheduled turnaround. The after-tax expenses for the Port
Reading turnaround were approximately $30 million. The
turnaround expenses are included in Other operating expenses, in
the Statement of Consolidated Income.
The following table summarizes refinery utilization rates:
|
Refinery
|
Refinery Utilization | |||||||||||||||
| Capacity | 2010 | 2009 | 2008 | |||||||||||||
|
(Thousands of
|
||||||||||||||||
| barrels per day) | ||||||||||||||||
|
HOVENSA
|
||||||||||||||||
|
Crude
|
500 | 78.0 | % | 80.3 | % | 88.2 | % | |||||||||
|
Fluid catalytic cracker
|
150 | 66.5 | % | 70.2 | % | 72.7 | % | |||||||||
|
Coker
|
58 | 78.3 | % | 81.6 | % | 92.4 | % | |||||||||
|
Port Reading
|
70 | 78.1 | % | 90.2 | % | 90.7 | % | |||||||||
In January 2011, HOVENSA announced plans to shut down certain
older and smaller processing units on the west side of its
refinery, which will reduce the refinery’s crude oil
distillation capacity from 500,000 to 350,000 barrels per
day, with no impact on the capacity of its coker or FCC unit.
This reconfiguration, which is expected to be completed in the
first quarter of 2011, is being undertaken to improve
efficiency, reliability and competitiveness.
Marketing:
Marketing operations, which
consist principally of retail gasoline and energy marketing
activities, generated income of $215 million in 2010,
$168 million in 2009 and $240 million in 2008. The
increase in earnings in 2010 compared with 2009 reflects
improved margins from the weak economic environment in 2009.
30
Table of Contents
The table below summarizes marketing sales volumes:
| 2010 | 2009 | 2008 | ||||||||||
|
Refined product sales (thousands of barrels per day)
|
471 | 473 | 472 | |||||||||
|
Natural gas (thousands of mcf per day)
|
2,016 | 2,010 | 1,955 | |||||||||
|
Electricity (megawatts round the clock)
|
4,140 | 4,306 | 3,152 | |||||||||
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 a loss of $1 million in
2010, earnings of $46 million in 2009 and a loss of
$36 million in 2008.
Marketing expenses increased in 2010 compared with 2009 and
decreased in 2009 as compared with 2008, principally reflecting
changes in retail credit card fees.
The Corporation’s future M&R earnings may be impacted
by supply and demand factors, volatility in margins, credit
risks, the effects of weather, competitive industry conditions,
political risk, environmental risk and catastrophic risk. For a
more comprehensive description of the risks that may affect the
Corporation’s M&R business, see Item 1A. Risk
Factors Related to Our Business and Operations.
Corporate
The following table summarizes corporate expenses:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Corporate expenses (excluding items affecting comparability)
|
$ | 256 | $ | 227 | $ | 260 | ||||||
|
Income taxes (benefits)
|
(104 | ) | (82 | ) | (87 | ) | ||||||
|
Net corporate expenses
|
152 | 145 | 173 | |||||||||
|
Items affecting comparability between periods, after-tax
|
7 | 60 | — | |||||||||
|
Total corporate expenses, after-tax
|
$ | 159 | $ | 205 | $ | 173 | ||||||
Excluding items affecting comparability between periods, the
increase in corporate expenses in 2010 compared with 2009
primarily reflects higher employee and insurance costs, and bank
facility fees. The decrease in corporate expenses in 2009
compared with 2008 primarily reflects gains on supplemental
pension related investments and lower employee and professional
costs. After-tax corporate expenses in 2011 are estimated to be
in the range of $165 to $175 million.
In 2009, the Corporation recorded pre-tax charges of
$54 million ($34 million after income taxes) related
to the repurchase of $546 million in fixed-rate notes that
were scheduled to mature in 2011 and $42 million
($26 million after income taxes) relating to retirement
benefits and employee severance costs. In 2010, the Corporation
recorded a pre-tax charge of $11 million ($7 million
after income taxes) related to the repurchase of the remaining
$116 million of notes that were scheduled to mature in
2011. The pre-tax charges in connection with the debt
repurchases were recorded in Other, net, and the pre-tax amounts
of the retirement benefits and severance costs were recorded in
General and administrative expenses within the Statement of
Consolidated Income.
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Interest
Interest expense was as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Total interest incurred
|
$ | 366 | $ | 366 | $ | 274 | ||||||
|
Less capitalized interest
|
5 | 6 | 7 | |||||||||
|
Interest expense before income taxes
|
361 | 360 | 267 | |||||||||
|
Less income taxes
|
140 | 136 | 100 | |||||||||
|
After-tax interest expense
|
$ | 221 | $ | 224 | $ | 167 | ||||||
Interest expense was comparable in 2010 and 2009. The increase
in interest expense in 2009 compared to 2008 primarily reflects
higher debt and fees for letters of credit. After-tax interest
expense in 2011 is expected to be in the range of $240 to
$250 million.
Sales
and Other Operating Revenues
Sales and other operating revenues totaled $33,862 million
in 2010, $29,614 million in 2009 and $41,134 million
in 2008. In 2010, sales and other operating revenues increased
by 14% compared with 2009. In 2009, sales and other operating
revenues decreased by 28% compared with 2008. 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 purchase prices of
refined products, 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:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Cash and cash equivalents
|
$ | 1,608 | $ | 1,362 | ||||
|
Short-term debt and current maturities of long-term debt
|
$ | 46 | $ | 148 | ||||
|
Total debt
|
$ | 5,583 | $ | 4,467 | ||||
|
Total equity
|
$ | 16,809 | $ | 13,528 | ||||
|
Debt to capitalization ratio*
|
24.9 | % | 24.8 | % | ||||
| * | 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:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$ | 4,530 | $ | 3,046 | $ | 4,688 | ||||||
|
Investing activities
|
(5,259 | ) | (2,924 | ) | (4,444 | ) | ||||||
|
Financing activities
|
975 | 332 | 57 | |||||||||
|
Net increase in cash and cash equivalents
|
$ | 246 | $ | 454 | $ | 301 | ||||||
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Table of Contents
Operating Activities:
Net cash provided
by operating activities, including changes in operating assets
and liabilities, was $4,530 million in 2010 compared with
$3,046 million in 2009, reflecting higher earnings.
Operating cash flow decreased to $3,046 million in 2009
from $4,688 million in 2008 reflecting lower earnings.
Investing Activities:
The following
table summarizes the Corporation’s capital expenditures:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Exploration and Production
|
||||||||||||
|
Exploration
|
$ | 552 | $ | 611 | $ | 744 | ||||||
|
Production and development
|
2,592 | 1,927 | 2,523 | |||||||||
|
Acquisitions (including leaseholds)
|
2,250 | 262 | 984 | |||||||||
| 5,394 | 2,800 | 4,251 | ||||||||||
|
Marketing, Refining and Corporate
|
98 | 118 | 187 | |||||||||
|
Total
|
$ | 5,492 | $ | 2,918 | $ | 4,438 | ||||||
Capital expenditures in 2010 include acquisitions of
167,000 net acres in the Bakken oil shale play in North
Dakota from TRZ Energy, LLC for $1,075 million in cash and
additional interests of 8% and 13% in the Valhall and Hod
fields, respectively, for $507 million in cash.
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.
Financing Activities:
During 2010, net
proceeds from borrowings were $1,098 million. In August
2010, the Corporation issued $1,250 million of 30 year
fixed-rate notes with a coupon of 5.6% scheduled to mature in
2041. The proceeds were used to purchase additional acreage in
the Bakken and additional interests in the Valhall and Hod
fields. In January 2010, the Corporation completed the
repurchase of the remaining $116 million of notes that were
scheduled to mature in 2011. During 2009, net proceeds from
borrowings were $447 million, compared with net repayments
of debt of $32 million in 2008.
Total common stock dividends paid were $131 million in 2010
and 2009 and $130 million in 2008. The Corporation received
net proceeds from the exercise of stock options, including
related income tax benefits of $54 million,
$18 million and $340 million in 2010, 2009 and 2008,
respectively.
Future
Capital Requirements and Resources
The Corporation anticipates investing a total of approximately
$5.6 billion in capital and exploratory expenditures during
2011, substantially all of which is targeted for E&P
operations. In the Corporation’s M&R operations,
refining margins continue to be weak, which have adversely
affected HOVENSA’s liquidity position. The Corporation
intends to provide its share of financial support for HOVENSA.
The Corporation expects to fund its 2011 operations, including
capital expenditures, dividends, pension contributions, required
debt repayments and financial support for HOVENSA, with existing
cash on-hand, cash flow from operations, proceeds from the sale
of United Kingdom natural gas assets 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.
33
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, 2010:
|
Expiration
|
Letters of
|
Available
|
||||||||||||||||||||
| Date | Capacity | Borrowings | Credit Issued | Total Used | Capacity | |||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||
|
Revolving credit facility
|
May 2012(a) | $ | 3,000 | $ | — | $ | — | $ | — | $ | 3,000 | |||||||||||
|
Asset-backed credit facility
|
July 2011(b) | 530 | — | 400 | 400 | 130 | ||||||||||||||||
|
Committed lines
|
Various(c) | 2,925 | — | 1,161 | 1,161 | 1,764 | ||||||||||||||||
|
Uncommitted lines
|
Various(c) | 521 | — | 521 | 521 | — | ||||||||||||||||
|
Total
|
$ | 6,976 | $ | — | $ | 2,082 | $ | 2,082 | $ | 4,894 | ||||||||||||
| (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 through 2013. |
The Corporation has a $3 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, 2010, the Corporation has
available capacity on the facility of $3 billion.
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 to borrow or issue
letters of credit of up to $1 billion subject to the
availability of sufficient levels of eligible receivables. At
December 31, 2010, outstanding letters of credit under this
facility were collateralized by a total of $1,194 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.
The Corporation’s long-term debt agreements contain a
financial covenant that restricts the amount of total borrowings
and secured debt. At December 31, 2010, the Corporation is
permitted to borrow up to an additional $22.4 billion for
the construction or acquisition of assets. The Corporation has
the ability to borrow up to an additional $4.4 billion of
secured debt at December 31, 2010.
The Corporation’s $2,082 million in letters of credit
outstanding at December 31, 2010 were primarily issued to
satisfy margin requirements. See also Note 16, 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 with a stable outlook 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.
34
Table of Contents
Contractual
Obligations and Contingencies
Following is a table showing aggregated information about
certain contractual obligations at December 31, 2010:
| Payments Due by Period | ||||||||||||||||||||
|
2012 and
|
2014 and
|
|||||||||||||||||||
| Total | 2011 | 2013 | 2015 | Thereafter | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
Total debt*
|
$ | 5,583 | $ | 46 | $ | 72 | $ | 345 | $ | 5,120 | ||||||||||
|
Operating leases
|
3,077 | 410 | 840 | 558 | 1,269 | |||||||||||||||
|
Purchase obligations
|
||||||||||||||||||||
|
Supply commitments**
|
32,376 | 12,233 | 10,264 | 9,862 | 17 | |||||||||||||||
|
Capital expenditures and other investments
|
2,382 | 1,798 | 494 | 89 | 1 | |||||||||||||||
|
Operating expenses
|
1,677 | 830 | 483 | 214 | 150 | |||||||||||||||
|
Other long-term liabilities
|
2,308 | 204 | 326 | 310 | 1,468 | |||||||||||||||
| * | At December 31, 2010, the Corporation’s debt bears interest at a weighted average rate of 6.8 %. | |
| ** | The Corporation intends to continue purchasing refined product supply from HOVENSA. Estimated future purchases amount to approximately $5 billion annually using year-end 2010 prices, which have been included in the table through 2015. |
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, actual refinery output and the amount of product sold by
HOVENSA to unaffiliated third parties. Under the product sales
agreement between the Corporation and HOVENSA, HOVENSA is
entitled to reserve refined products for sale to unaffiliated
third parties each month up to a maximum amount set by the
executive committee of HOVENSA annually. The Corporation is
obligated to purchase 50% of the remaining refined products
produced by HOVENSA, including amounts reserved for third party
sales by HOVENSA that remain unsold. The prices at which the
Corporation purchases refined products are determined by
reference to published market prices prevailing at the time of
purchase. The amount of the purchase commitment from HOVENSA is
based on the forecasted refinery output that is expected to be
sold to the Corporation calculated using year-end prices.
Also included above 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 $5.6 billion
capital investment program for 2011 that is contractually
committed at December 31, 2010. 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, 2010, 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.
As of December 31, 2010, 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 $190 million.
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, 2010 it amounted to
$150 million. In addition, the Corporation
35
Table of Contents
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.
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, 2010 as shown below
(in millions):
|
Letters of credit
|
$ | 81 | ||
|
Guarantees
|
165 | |||
| $ | 246 | |||
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
$394 million at December 31, 2010 compared with
$412 million at December 31, 2009. The
Corporation’s December 31, 2010 debt to capitalization
ratio would increase from 24.9% to 26.2% if these leases were
included as debt.
See also Note 4, Refining Joint Venture, and Note 17,
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, Brunei, China, Colombia, Denmark, Egypt,
Equatorial Guinea, France, 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. In production operations, costs of
injected
CO
2
for tertiary recovery are expensed as incurred.
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 operational
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.
36
Table of Contents
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 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 engages 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
37
Table of Contents
synergies including cost savings, access to new business
opportunities, enterprise control, improved processes and
increased market share. The Corporation also considers the
relative market valuation of similar Exploration and Production
companies.
The determination of the fair value of the 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.
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 may have occurred. The
fair value measurement used in the impairment assessment is
based on quoted market prices, where available, or other
valuation techniques, including discounted cash flows.
Differences between the carrying value of the Corporation’s
equity investments and its equity in the net assets of the
affiliate that result from impairment charges are amortized over
the remaining useful life of the affiliate’s fixed assets.
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 available carryforward periods for net operating
losses and credit carryforwards, temporary differences, the
availability of tax planning strategies, the existence of
appreciated assets and estimates of future taxable income 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 as appropriate. 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 also records certain nonfinancial assets and
liabilities at fair value when required by generally accepted
accounting principles. These fair value measurements are
recorded in connection with business combinations, the initial
recognition of asset retirement obligations and any impairment
of long-lived assets, equity method investments or goodwill.
The Corporation determines fair value in accordance with the
FASB fair value measurements accounting standard which
established a hierarchy for the inputs used to measure the fair
value of financial asset and liabilities based on the source of
the input, which generally range from quoted prices for
identical instruments in a principal
38
Table of Contents
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.
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.
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 and other
unobservable data 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.
39
Table of Contents
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
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
Effective January 1, 2010, the Corporation adopted the
amended accounting standards that eliminated the consolidation
exception for a qualifying special-purpose entity and changed
the analysis necessary to determine whether consolidation of a
variable interest entity is required. The adoption of these
standards resulted in an increase of approximately
$10 million to Property, plant and equipment and a
corresponding increase to Long-term debt. The debt was
subsequently repaid during the first quarter of 2010.
Effective December 31, 2009, the FASB adopted Accounting
Standards Update (ASU) Extractive Activities — Oil and
Gas (ASC 932) Oil and Gas Reserve Estimation and
Disclosures, which amended the requirements for oil and gas
reserve estimation and disclosures. The main provisions of the
ASU, which align accounting standards with the previously issued
Securities and Exchange Commission (SEC) requirements, 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.
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
40
Table of Contents
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. Many states and
localities are adopting requirements that mandate a lower sulfur
content of fuel oils and restrict the types of fuel oil sold
within their jurisdictions. These proposals could require
capital expenditures by the Corporation and HOVENSA to meet the
required sulfur content standards or other changes in the
marketing of fuel oils.
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. In
January 2011, HOVENSA signed a Consent Decree with EPA to
resolve its claims. Under the terms of the Consent Decree,
HOVENSA will pay a penalty of approximately $5 million and
spend approximately $700 million over the next
10 years to install equipment and implement additional
operating procedures at the HOVENSA refinery to reduce
emissions. In addition, the Consent Decree requires HOVENSA to
spend approximately $5 million to fund an environmental
project to be determined at a later date by the Virgin Islands
and $500,000 to assist the Virgin Islands Water and Power
Authority with monitoring. The Consent Decree has been lodged
with the United States District Court for the Virgin Islands and
approval is pending. In addition, substantial progress has been
made towards resolving this matter for the Port Reading refining
facility, which is not expected to have a material adverse
impact on the Corporation’s financial position or results
of operations.
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.
The Corporation accrues for environmental assessment and
remediation expenses when the future costs are probable and
reasonably estimable. At year-end 2010, the Corporation’s
reserve for estimated remediation liabilities was approximately
$55 million. The Corporation expects that existing reserves
for environmental liabilities will adequately cover costs to
assess and remediate known sites. The Corporation’s
remediation spending was $13 million in 2010 and
$11 million in both 2009 and 2008. Capital expenditures for
facilities, primarily to comply with federal, state and local
environmental standards, other than for the low sulfur
requirements, were approximately $85 million in 2010,
$50 million in 2009 and $15 million in 2008.
Forward-Looking
Information
Certain sections of this Annual Report on
Form 10-K,
including Business and Properties, Management’s Discussion
and Analysis of Financial Condition and Results of Operations
and Quantitative and Qualitative Disclosures about Market Risk,
include 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, which 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
41
Table of Contents
future. Actual results may differ from these disclosures because
of changes in market conditions, government actions and other
factors. For more information regarding the factors that may
cause the Corporation’s results to differ from these
statements, see Item 1A Risk Factors Related to Our
Business and Operations.
| 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. In the
disclosures that follow, these risk management activities are
referred to as energy marketing and corporate risk management.
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 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. | |
| • | 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 risk management and trading activities. Cash flows from swap contracts are determined based on underlying commodity prices or interest rates 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. |
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Table of Contents
| • | 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, refined products
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 and the Thai Baht. At December 31, 2010, the
Corporation had a payable for foreign exchange contracts
maturing in 2011 with a fair value of $7 million. The
change in fair value of the foreign exchange contracts from a
10% strengthening of the US Dollar exchange rate is
estimated to be an approximately $88 million loss at
December 31, 2010.
The Corporation’s fixed-rate debt of $5,569 million
has a fair value of $6,353 million at December 31,
2010. A 15% decrease in the rate of interest would increase the
fair value of debt by approximately $147 million at
December 31, 2010.
Following is the value at risk for the Corporation’s energy
marketing and risk management commodity derivatives activities,
excluding foreign exchange and interest derivatives described
above:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
At December 31
|
$ | 5 | $ | 8 | ||||
|
Average
|
5 | 10 | ||||||
|
High
|
6 | 13 | ||||||
|
Low
|
4 | 8 | ||||||
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:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
At December 31
|
$ | 14 | $ | 9 | ||||
|
Average
|
14 | 12 | ||||||
|
High
|
15 | 15 | ||||||
|
Low
|
12 | 9 | ||||||
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Derivative trading transactions are
marked-to-market
and unrealized gains or losses are recognized currently in
earnings. Gains or losses from sales of physical products are
recorded at the time of sale. Total realized gains on trading
activities amounted to $375 million in 2010 and
$642 million in 2009. 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:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Fair value of contracts outstanding at the beginning of the year
|
$ | 110 | $ | 864 | ||||
|
Change in fair value of contracts outstanding at the beginning
of the year and still outstanding at the end of the year
|
10 | (6 | ) | |||||
|
Reversal of fair value for contracts closed during the year
|
(233 | ) | (534 | ) | ||||
|
Fair value of contracts entered into during the year and still
outstanding
|
207 | (214 | ) | |||||
|
Fair value of contracts outstanding at the end of the year
|
$ | 94 | $ | 110 | ||||
The following table summarizes the sources of fair values of
derivatives used in the Corporation’s trading activities at
December 31, 2010:
|
2014 and
|
||||||||||||||||||||||||
| Total | 2011 | 2012 | 2013 | Beyond | ||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Source of fair value
|
||||||||||||||||||||||||
|
Level 1
|
$ | (252 | ) | $ | (305 | ) | $ | 46 | $ | 5 | $ | 2 | ||||||||||||
|
Level 2
|
(34 | ) | (89 | ) | 44 | 8 | 3 | |||||||||||||||||
|
Level 3
|
380 | 352 | (14 | ) | (2 | ) | 44 | |||||||||||||||||
|
Total
|
$ | 94 | $ | (42 | ) | $ | 76 | $ | 11 | $ | 49 | |||||||||||||
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:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Investment grade determined by outside sources
|
$ | 314 | $ | 232 | ||||
|
Investment grade determined internally*
|
272 | 120 | ||||||
|
Less than investment grade
|
48 | 61 | ||||||
|
Fair value of net receivables outstanding at the end of the year
|
$ | 634 | $ | 413 | ||||
| * | Based on information provided by counterparties and other available sources. |
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| 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 | ||||
| 46 | ||||
| 47 | ||||
| 49 | ||||
| 50 | ||||
| 51 | ||||
| 52 | ||||
| 53 | ||||
| 88 | ||||
| 98 | ||||
| 106 | ||||
| * | 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. |
45
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, 2010.
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, 2010, as stated in their
report, which is included herein.
|
By
|
|
By |
|
|||
| John P. Rielly | John B. Hess | |||||
| Senior Vice President and | Chairman of the Board and | |||||
| Chief Financial Officer | Chief Executive Officer |
February 25, 2011
46
Table of Contents
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, 2010, 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, 2010 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, 2010 and 2009, 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, 2010, and our report dated
February 25, 2011 expressed an unqualified opinion thereon.
February 25, 2011
New York, New York
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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, 2010 and 2009,
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, 2010. 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, 2010 and 2009, and the
consolidated results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2010, 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.
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, 2010, 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 25, 2011 expressed an unqualified
opinion thereon.
February 25, 2011
New York, New York
48
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions of dollars; thousands of shares) | ||||||||
|
ASSETS
|
||||||||
|
CURRENT ASSETS
|
||||||||
|
Cash and cash equivalents
|
$ | 1,608 | $ | 1,362 | ||||
|
Accounts receivable
|
||||||||
|
Trade
|
4,478 | 3,650 | ||||||
|
Other
|
240 | 274 | ||||||
|
Inventories
|
1,452 | 1,438 | ||||||
|
Other current assets
|
1,002 | 1,263 | ||||||
|
Total current assets
|
8,780 | 7,987 | ||||||
|
INVESTMENTS IN AFFILIATES
|
||||||||
|
HOVENSA L.L.C.
|
158 | 681 | ||||||
|
Other
|
285 | 232 | ||||||
|
Total investments in affiliates
|
443 | 913 | ||||||
|
PROPERTY, PLANT AND EQUIPMENT
|
||||||||
|
Total — at cost
|
35,703 | 29,871 | ||||||
|
Less reserves for depreciation, depletion, amortization and
lease impairment
|
14,576 | 13,244 | ||||||
|
Property, plant and equipment — net
|
21,127 | 16,627 | ||||||
|
GOODWILL
|
2,408 | 1,225 | ||||||
|
DEFERRED INCOME TAXES
|
2,167 | 2,409 | ||||||
|
OTHER ASSETS
|
471 | 304 | ||||||
|
TOTAL ASSETS
|
$ | 35,396 | $ | 29,465 | ||||
| LIABILITIES AND EQUITY | ||||||||
|
CURRENT LIABILITIES
|
||||||||
|
Accounts payable
|
$ | 4,274 | $ | 4,223 | ||||
|
Accrued liabilities
|
2,567 | 1,954 | ||||||
|
Taxes payable
|
726 | 525 | ||||||
|
Short-term debt and current maturities of long-term debt
|
46 | 148 | ||||||
|
Total current liabilities
|
7,613 | 6,850 | ||||||
|
LONG-TERM DEBT
|
5,537 | 4,319 | ||||||
|
DEFERRED INCOME TAXES
|
2,995 | 2,222 | ||||||
|
ASSET RETIREMENT OBLIGATIONS
|
1,203 | 1,234 | ||||||
|
OTHER LIABILITIES AND DEFERRED CREDITS
|
1,239 | 1,312 | ||||||
|
Total liabilities
|
18,587 | 15,937 | ||||||
|
EQUITY
|
||||||||
|
Common stock, par value $1.00
|
||||||||
|
Authorized: 600,000 shares
|
||||||||
|
Issued: 2010 — 337,681 shares; 2009 —
327,229 shares
|
338 | 327 | ||||||
|
Capital in excess of par value
|
3,256 | 2,481 | ||||||
|
Retained earnings
|
14,254 | 12,251 | ||||||
|
Accumulated other comprehensive income (loss)
|
(1,159 | ) | (1,675 | ) | ||||
|
Total Hess Corporation stockholders’ equity
|
16,689 | 13,384 | ||||||
|
Noncontrolling interests
|
120 | 144 | ||||||
|
Total equity
|
16,809 | 13,528 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 35,396 | $ | 29,465 | ||||
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.
49
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars, except per share data) | ||||||||||||
|
REVENUES AND NON-OPERATING INCOME
|
||||||||||||
|
Sales (excluding excise taxes) and other operating revenues
|
$ | 33,862 | $ | 29,614 | $ | 41,134 | ||||||
|
Income (loss) from equity investment in HOVENSA L.L.C.
|
(522 | ) | (229 | ) | 44 | |||||||
|
Gains on asset sales
|
1,208 | — | — | |||||||||
|
Other, net
|
65 | 184 | (115 | ) | ||||||||
|
Total revenues and non-operating income
|
34,613 | 29,569 | 41,063 | |||||||||
|
COSTS AND EXPENSES
|
||||||||||||
|
Cost of products sold (excluding items shown separately below)
|
23,407 | 20,961 | 29,567 | |||||||||
|
Production expenses
|
1,924 | 1,805 | 1,872 | |||||||||
|
Marketing expenses
|
1,021 | 1,008 | 1,025 | |||||||||
|
Exploration expenses, including dry holes and lease impairment
|
865 | 829 | 725 | |||||||||
|
Other operating expenses
|
213 | 183 | 209 | |||||||||
|
General and administrative expenses
|
662 | 647 | 672 | |||||||||
|
Interest expense
|
361 | 360 | 267 | |||||||||
|
Depreciation, depletion and amortization
|
2,317 | 2,200 | 1,999 | |||||||||
|
Asset impairments
|
532 | 54 | 30 | |||||||||
|
Total costs and expenses
|
31,302 | 28,047 | 36,366 | |||||||||
|
INCOME BEFORE INCOME TAXES
|
3,311 | 1,522 | 4,697 | |||||||||
|
Provision for income taxes
|
1,173 | 715 | 2,340 | |||||||||
|
NET INCOME
|
$ | 2,138 | $ | 807 | $ | 2,357 | ||||||
|
Less: Net income (loss) attributable to noncontrolling interests
|
13 | 67 | (3 | ) | ||||||||
|
NET INCOME ATTRIBUTABLE TO HESS CORPORATION
|
$ | 2,125 | $ | 740 | $ | 2,360 | ||||||
|
BASIC NET INCOME PER SHARE
|
$ | 6.52 | $ | 2.28 | $ | 7.35 | ||||||
|
DILUTED NET INCOME PER SHARE
|
$ | 6.47 | $ | 2.27 | $ | 7.24 | ||||||
|
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
(DILUTED)
|
328.3 | 326.0 | 325.8 | |||||||||
See accompanying notes to consolidated financial statements.
50
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net income
|
$ | 2,138 | $ | 807 | $ | 2,357 | ||||||
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
||||||||||||
|
Depreciation, depletion and amortization
|
2,317 | 2,200 | 1,999 | |||||||||
|
Asset impairments
|
532 | 54 | 30 | |||||||||
|
Exploratory dry hole costs
|
237 | 267 | 210 | |||||||||
|
Lease impairment
|
266 | 231 | 125 | |||||||||
|
(Income) loss from equity investment in HOVENSA L.L.C.
|
522 | 229 | (44 | ) | ||||||||
|
Stock compensation expense
|
112 | 128 | 119 | |||||||||
|
Gains on asset sales
|
(1,208 | ) | — | — | ||||||||
|
Benefit for deferred income taxes
|
(495 | ) | (438 | ) | (57 | ) | ||||||
|
Changes in operating assets and liabilities:
|
||||||||||||
|
(Increase) decrease in accounts receivable
|
(760 | ) | 320 | 357 | ||||||||
|
Increase in inventories
|
(16 | ) | (137 | ) | (56 | ) | ||||||
|
Increase (decrease) in accounts payable and accrued liabilities
|
1,141 | (542 | ) | (252 | ) | |||||||
|
Increase (decrease) in taxes payable
|
95 | (81 | ) | 61 | ||||||||
|
Changes in other assets and liabilities
|
(351 | ) | 8 | (161 | ) | |||||||
|
Net cash provided by operating activities
|
4,530 | 3,046 | 4,688 | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Capital expenditures
|
(5,492 | ) | (2,918 | ) | (4,438 | ) | ||||||
|
Proceeds from asset sales
|
183 | — | — | |||||||||
|
Other, net
|
50 | (6 | ) | (6 | ) | |||||||
|
Net cash used in investing activities
|
(5,259 | ) | (2,924 | ) | (4,444 | ) | ||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Net (repayments) borrowings of debt with maturities of
90 days or less
|
— | (850 | ) | 30 | ||||||||
|
Debt with maturities of greater than 90 days
|
||||||||||||
|
Borrowings
|
1,278 | 1,991 | — | |||||||||
|
Repayments
|
(180 | ) | (694 | ) | (62 | ) | ||||||
|
Cash dividends paid
|
(131 | ) | (131 | ) | (130 | ) | ||||||
|
Noncontrolling interests, net
|
(46 | ) | (2 | ) | (121 | ) | ||||||
|
Employee stock options exercised, including income tax benefits
|
54 | 18 | 340 | |||||||||
|
Net cash provided by financing activities
|
975 | 332 | 57 | |||||||||
|
NET INCREASE IN CASH AND CASH EQUIVALENTS
|
246 | 454 | 301 | |||||||||
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
1,362 | 908 | 607 | |||||||||
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$ | 1,608 | $ | 1,362 | $ | 908 | ||||||
See accompanying notes to consolidated financial statements.
51
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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, 2008
|
$ | 321 | $ | 1,882 | $ | 9,412 | $ | (1,841 | ) | $ | 9,774 | $ | 226 | $ | 10,000 | |||||||||||||
|
Net income (loss)
|
2,360 | 2,360 | (3 | ) | 2,357 | |||||||||||||||||||||||
|
Deferred gains (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 | ) | ||||||||||||||||||||
|
Comprehensive income (loss)
|
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 | ) | ||||||||||||||||||
|
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 gain (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 | |||||||||||||||||||||||
|
Comprehensive income (loss)
|
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 | ) | ||||||||||||||||||
|
Noncontrolling interests, net
|
— | — | — | — | — | (2 | ) | (2 | ) | |||||||||||||||||||
|
Balance at December 31, 2009
|
327 | 2,481 | 12,251 | (1,675 | ) | 13,384 | 144 | 13,528 | ||||||||||||||||||||
|
Net income
|
2,125 | 2,125 | 13 | 2,138 | ||||||||||||||||||||||||
|
Deferred gains (losses) on cash flow hedges, after-tax
|
||||||||||||||||||||||||||||
|
Effect of hedge losses recognized in income
|
656 | 656 | — | 656 | ||||||||||||||||||||||||
|
Net change in fair value of cash flow hedges
|
(198 | ) | (198 | ) | — | (198 | ) | |||||||||||||||||||||
|
Change in post retirement plan liabilities, after-tax
|
28 | 28 | — | 28 | ||||||||||||||||||||||||
|
Change in foreign currency translation adjustment and other
|
30 | 30 | 1 | 31 | ||||||||||||||||||||||||
|
Comprehensive income (loss)
|
2,641 | 14 | 2,655 | |||||||||||||||||||||||||
|
Common stock issued for acquisition
|
9 | 639 | — | — | 648 | — | 648 | |||||||||||||||||||||
|
Activity related to restricted common stock awards, net
|
1 | 59 | — | — | 60 | — | 60 | |||||||||||||||||||||
|
Employee stock options, including income tax benefits
|
1 | 105 | — | — | 106 | — | 106 | |||||||||||||||||||||
|
Cash dividends declared
|
— | — | (132 | ) | — | (132 | ) | — | (132 | ) | ||||||||||||||||||
|
Noncontrolling interests, net
|
— | (28 | ) | 10 | — | (18 | ) | (38 | ) | (56 | ) | |||||||||||||||||
|
Balance at December 31, 2010
|
$ | 338 | $ | 3,256 | $ | 14,254 | $ | (1,159 | ) | $ | 16,689 | $ | 120 | $ | 16,809 | |||||||||||||
See accompanying notes to consolidated financial statements.
52
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,
Brunei, China, Colombia, Denmark, Egypt, Equatorial Guinea,
France, Ghana, Indonesia, Libya, Malaysia, Norway, Peru, Russia,
Thailand, the United Kingdom and the United States. In addition,
the Corporation manufactures refined petroleum products and
purchases, markets and trades refined petroleum products,
natural gas and electricity. 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.
Certain information in the financial statements and notes has
been reclassified to conform to the current period presentation.
In the preparation of these financial statements, the
Corporation has evaluated subsequent events through the date of
issuance.
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 consolidates the trading partnership in which it
owns a 50% voting interest and over which it exercises control.
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 and where the Corporation has the ability to influence the
operating or financial decisions of the affiliate, including
HOVENSA, are accounted for using the equity method.
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
Exploration and Production (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 E&P activities, the Corporation engages in 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. Derivatives may be designated
as hedges of expected future cash flows or forecasted
transactions (cash flow hedges)
53
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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) while the ineffective portion
of the changes in fair value is recorded currently in earnings.
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.
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:
E&P 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. In
production operations, costs of injected
CO
2
for tertiary recovery are expensed as incurred.
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 operational
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.
54
Table of Contents
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 may have occurred. The
fair value measurement used in the impairment assessment is
based on quoted market prices, where available, or other
valuation techniques, including discounted cash flows.
Differences between the carrying value of the Corporation’s
equity investments and its equity in the net assets of the
affiliate that result from impairment charges are amortized over
the remaining useful life of the affiliate’s fixed assets.
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’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 as appropriate. 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.
55
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The Corporation also records certain nonfinancial assets and
liabilities at fair value when required by GAAP. These fair
value measurements are recorded in connection with business
combinations, the initial recognition of asset retirement
obligations and any impairment of long-lived assets, equity
method investments or goodwill.
The Corporation determines fair value in accordance with the
fair value measurements accounting standard which established a
hierarchy for the inputs used to measure the fair value of
financial assets and liabilities 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 is based on the lowest significant input
level within this fair value hierarchy.
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.
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 enters into
contracts to sell 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. Fair values
determined using discounted cash flows and other unobservable
data are also classified as Level 3.
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 funded status of defined benefit postretirement
plans on the balance sheet. The funded 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. 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.
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.
56
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 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
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:
Effective January 1, 2010, the
Corporation adopted the amended accounting standards that
eliminated the consolidation exception for a qualifying
special-purpose entity and changed the analysis necessary to
determine whether consolidation of a variable interest entity is
required. The adoption of these standards resulted in an
increase of approximately $10 million to Property, plant
and equipment and a corresponding increase to Long-term debt.
The debt was subsequently repaid during the first quarter of
2010.
Effective December 31, 2009, the Financial Accounting
Standards Board (FASB) adopted Accounting Standards Update (ASU)
Extractive Activities — Oil and Gas (ASC 932) Oil
and Gas Reserve Estimation and Disclosures, which amended the
requirements for oil and gas reserve estimation and disclosures.
The main provisions of the ASU, which align accounting standards
with the previously issued Securities and Exchange Commission
(SEC) requirements, 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.
| 2. | Acquisitions and Divestitures |
2010:
In December, the Corporation
acquired approximately 167,000 net acres in the Bakken oil
shale play (Bakken) in North Dakota from TRZ Energy, LLC for
$1,075 million in cash. In December, the Corporation also
completed the acquisition of American Oil & Gas Inc.
(American Oil & Gas) for approximately
$675 million through the issuance of approximately
8.6 million shares of the Corporation’s common stock,
which increased the Corporation’s acreage position in the
Bakken by approximately 85,000 net acres. The properties
acquired are located near the Corporation’s existing
acreage. These acquisitions strengthen the Corporation’s
acreage position in the Bakken, leverage existing capabilities
and infrastructure and are expected to contribute to future
reserve and production growth. Both of these transactions were
accounted for as business combinations and the majority of the
fair value of the assets acquired was assigned to unproved
properties. The total goodwill recorded on these transactions
was $347 million. The preliminary purchase price
allocations are subject to normal post-closing adjustments.
In September, the Corporation completed the exchange of its
interests in Gabon and the Clair Field in the United Kingdom for
additional interests of 28% and 25%, respectively, in the
Valhall and Hod fields offshore Norway. This non-monetary
exchange was accounted for as a business combination and was
recorded at fair value. The transaction resulted in a pre-tax
gain of $1,150 million ($1,072 million after income
taxes). The total combined carrying amount of the disposed
assets prior to the exchange was $702 million, including
goodwill of $65 million. The Corporation also acquired,
from a different third party, additional interests of 8% and 13%
in the Valhall and Hod fields, respectively, for
$507 million in cash. This acquisition was accounted for as
a business combination. As a result of both of these
transactions, the Corporation’s total interests in the
Valhall and Hod fields are 64% and 63%, respectively. The
primary
57
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
reason for these transactions was to acquire long-lived crude
oil reserves and future production growth. The following table
summarizes the fair value of the assets acquired and liabilities
assumed in both of these transactions:
| Exchange | Acquisition | Total | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Property, plant and equipment
|
$ | 2,020 | $ | 570 | $ | 2,590 | ||||||
|
Goodwill
|
688 | 220 | 908 | |||||||||
|
Current assets
|
155 | 23 | 178 | |||||||||
|
Total assets acquired
|
2,863 | 813 | 3,676 | |||||||||
|
Current liabilities
|
(135 | ) | (32 | ) | (167 | ) | ||||||
|
Deferred tax liabilities
|
(688 | ) | (220 | ) | (908 | ) | ||||||
|
Asset retirement obligations
|
(188 | ) | (54 | ) | (242 | ) | ||||||
|
Net assets acquired
|
$ | 1,852 | $ | 507 | $ | 2,359 | ||||||
For all 2010 acquisitions and the exchange described above, the
assets acquired and liabilities assumed are recorded at fair
value. The estimated fair value of the property, plant and
equipment acquired in the transactions described above was
primarily based on an income approach. The significant inputs
used in this Level 3 fair value measurement include assumed
future production and capital based on anticipated development
plans, commodity prices, costs and a risk-adjusted discount
rate. The goodwill recorded equals the deferred tax liability
recognized for the differences in book and tax bases of the
assets acquired. The goodwill is not expected to be deductible
for income tax purposes.
In January, the Corporation completed the sale of its interest
in the Jambi Merang natural gas development project in Indonesia
(Hess 25%) for cash proceeds of $183 million. The
transaction resulted in a gain of $58 million, after
deducting the net book value of assets including goodwill of
$7 million.
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% interest in its Gabonese subsidiary for
$285 million. In addition, 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.
| 3. | Inventories |
Inventories at December 31 are as follows:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Crude oil and other charge stocks
|
$ | 496 | $ | 424 | ||||
|
Refined products and natural gas
|
1,528 | 1,429 | ||||||
|
Less: LIFO adjustment
|
(995 | ) | (815 | ) | ||||
| 1,029 | 1,038 | |||||||
|
Merchandise, materials and supplies
|
423 | 400 | ||||||
|
Total
|
$ | 1,452 | $ | 1,438 | ||||
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The percentage of LIFO inventory to total crude oil, refined
products and natural gas inventories was 65% and 64% at
December 31, 2010 and 2009, respectively. In 2009, the
Corporation recorded a pre-tax charge of approximately
$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.
| 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:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Summarized Balance Sheet, at December 31
|
||||||||||||
|
Cash and cash equivalents
|
$ | 45 | $ | 78 | $ | 75 | ||||||
|
Other current assets
|
668 | 580 | 664 | |||||||||
|
Net fixed assets
|
1,987 | 2,080 | 2,136 | |||||||||
|
Other assets
|
27 | 33 | 58 | |||||||||
|
Current liabilities
|
(1,001 | ) | (953 | ) | (679 | ) | ||||||
|
Long-term debt
|
(706 | ) | (356 | ) | (356 | ) | ||||||
|
Deferred liabilities and credits
|
(135 | ) | (137 | ) | (104 | ) | ||||||
|
Members’ equity
|
$ | 885 | $ | 1,325 | $ | 1,794 | ||||||
|
Summarized Income Statement, for the years ended December 31
|
||||||||||||
|
Total revenues
|
$ | 12,300 | $ | 10,085 | $ | 17,518 | ||||||
|
Costs and expenses
|
(12,738 | ) | (10,536 | ) | (17,423 | ) | ||||||
|
Net income (loss)
|
$ | (438 | ) | $ | (451 | ) | $ | 95 | ||||
|
Hess Corporation’s share*
|
$ | (222 | ) | $ | (229 | ) | $ | 44 | ||||
|
Summarized Cash Flow Statement, for the years ended December 31
|
||||||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$ | (335 | ) | $ | 87 | $ | (20 | ) | ||||
|
Investing activities
|
(48 | ) | (84 | ) | (85 | ) | ||||||
|
Financing activities
|
350 | — | (99 | ) | ||||||||
|
Net increase (decrease) in cash and cash equivalents
|
$ | (33 | ) | $ | 3 | $ | (204 | ) | ||||
| * | Before Virgin Islands income taxes, which were recorded in the Corporation’s income tax provision. Excludes the impairment charge to reduce the carrying value of the Corporation’s equity investment in HOVENSA. |
In December 2010, the Corporation recorded an impairment charge
of $300 million before income taxes ($289 million
after income taxes) to reduce the carrying value of its equity
investment in HOVENSA to its fair value, which was recorded in
Income (loss) from equity investment in HOVENSA L.L.C. The
investment had been adversely affected by consecutive annual
operating losses resulting from continued weak refining margins
and refinery utilization and a fourth quarter 2010 debt rating
downgrade. As a result of a strategic assessment in 2010,
HOVENSA decided to lower crude oil refining capacity from
500,000 to 350,000 barrels per day. The Corporation
performed an impairment analysis and concluded that its
investment had experienced an other than temporary decline in
value. The fair value was determined based on an income approach
using estimated refined product
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
selling prices and volumes, related costs of product sold,
capital and operating expenditures and a market based discount
rate (Level 3 fair value measurement). As a result of cumulative
net operating losses in the last two years, the Corporation is
not recognizing a full income tax benefit on the impairment
charge.
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 $150 million at
December 31, 2010. 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.
| 5. | Property, Plant and Equipment |
Property, plant and equipment at December 31 consists of the
following:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Exploration and Production
|
||||||||
|
Unproved properties
|
$ | 3,796 | $ | 2,347 | ||||
|
Proved properties
|
3,496 | 3,121 | ||||||
|
Wells, equipment and related facilities
|
26,064 | 22,118 | ||||||
| 33,356 | 27,586 | |||||||
|
Marketing, Refining and Corporate
|
2,347 | 2,285 | ||||||
|
Total — at cost
|
35,703 | 29,871 | ||||||
|
Less: reserves for depreciation, depletion, amortization and
lease impairment
|
14,576 | 13,244 | ||||||
|
Property, plant and equipment — net
|
$ | 21,127 | $ | 16,627 | ||||
In March 2010, the Corporation agreed to sell a package of
natural gas producing assets in the United Kingdom North Sea
including its interests in the Easington Catchment Area (Hess
30%), the Bacton Area (Hess 23%), the Everest Field (Hess 19%),
the Lomond Field (Hess 17%) and its interest in the Central Area
Transmission System (CATS) pipeline (Hess 18%). The Corporation
has classified all of these properties as held for sale. At
December 31, 2010, the carrying amount of these assets
totaling $238 million was reported in Other current assets.
In addition, related asset retirement obligations and deferred
income taxes totaling $212 million were reported in Accrued
liabilities. In accordance with GAAP, properties classified as
held for sale are not depreciated but are subject to impairment
testing.
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:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Beginning balance at January 1
|
$ | 1,437 | $ | 1,094 | $ | 608 | ||||||
|
Additions to capitalized exploratory well costs pending the
determination of proved reserves
|
675 | 433 | 560 | |||||||||
|
Reclassifications to wells, facilities, and equipment based on
the determination of proved reserves
|
(87 | ) | (16 | ) | (67 | ) | ||||||
|
Capitalized exploratory well costs charged to expense
|
(110 | ) | (74 | ) | (7 | ) | ||||||
|
Dispositions
|
(132 | ) | — | — | ||||||||
|
Ending balance at December 31
|
$ | 1,783 | $ | 1,437 | $ | 1,094 | ||||||
|
Number of wells at end of year
|
82 | * | 53 | 45 | ||||||||
| * | The number of wells at the end of 2010 reflects increased onshore exploration activities, principally in the United States. |
60
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Capitalized exploratory well costs charged to expense in the
preceding table include $22 million related to the
impairment of the West Med Block and $79 million related to
the Azulão well in Brazil. Dispositions consist of well
costs relating to the Corporation’s 50% interest in
WA-404-P Block located offshore Western Australia and the Clair
Field, in the United Kingdom North Sea. The preceding table
excludes exploratory dry hole costs of $127 million,
$193 million and $203 million in 2010, 2009 and 2008,
respectively, which were incurred and subsequently expensed in
the same year.
At December 31, 2010, exploratory drilling costs
capitalized in excess of one year past completion of drilling
were as follows (in millions):
|
2009
|
$ | 500 | ||
|
2008
|
439 | |||
|
2007
|
95 | |||
|
2006
|
186 | |||
|
2003 to 2005
|
56 | |||
| $ | 1,276 | |||
The capitalized well costs in excess of one year relate to 15
projects. Approximately 49% of the capitalized well costs in
excess of one year relates to two separate projects in the
deepwater Gulf of Mexico, Pony and Tubular Bells, where
development planning is progressing. In addition, at the Pony
prospect the Corporation has signed a non-binding agreement in
principle with the owners on adjacent Green Canyon
Block 512 that outlines a proposal to jointly develop the
Pony and Knotty Head fields. Negotiation of a joint operating
agreement is ongoing. Approximately 21% of the capitalized well
costs in excess of one year relates to Area 54 offshore Libya
where commercial analysis and development planning activities
are ongoing. Approximately 18% relates to Block WA-390-P
offshore Western Australia where further drilling, other
appraisal activities and commercial analysis are ongoing. The
remainder of the capitalized well costs in excess of one year
relates 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. | Goodwill |
The changes in the carrying amount of goodwill are as follows:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Beginning balance at January 1
|
$ | 1,225 | $ | 1,225 | ||||
|
Acquisitions*
|
1,255 | — | ||||||
|
Dispositions*
|
(72 | ) | — | |||||
|
Ending balance at December 31
|
$ | 2,408 | $ | 1,225 | ||||
| * | For a description of the acquisitions and dispositions in 2010 refer to Note 2, Acquisitions and Divestitures. |
| 7. | Asset Impairments |
During 2010, the Corporation recorded a charge of
$532 million ($334 million after income taxes) to
fully impair the carrying value of its 55% interest in the West
Mediterranean Block 1 concession (West Med Block), located
offshore Egypt. This interest was acquired in 2006 and included
four natural gas discoveries and additional exploration
prospects. The Corporation and its partners subsequently
explored and further evaluated the area, made a fifth discovery,
conducted development planning, and held negotiations with the
Egyptian authorities to amend the existing gas sales agreement.
In September 2010, the Corporation and its partners notified the
Egyptian authorities of their decision to cease exploration
activities on the block and to relinquish a significant portion
of the block. As a result, the Corporation fully impaired the
carrying value of its interests in the West Med Block. The
61
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Corporation’s estimated fair value of the West Med Block
was determined using a valuation approach based on market
related data (Level 3 fair value measurement).
During 2009, the Corporation recorded total asset impairment
charges of $54 million ($26 million after income
taxes) to reduce the carrying value of two short-lived fields in
the United Kingdom North Sea. During 2008, the Corporation
recorded total asset impairment charges of $30 million
($17 million after income taxes) to reduce the carrying
value of mature fields in the United States and the United
Kingdom North Sea.
| 8. | Asset Retirement Obligations |
The following table describes changes to the Corporation’s
asset retirement obligations:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Asset retirement obligations at January 1
|
$ | 1,297 | $ | 1,214 | ||||
|
Liabilities incurred
|
255 | 14 | ||||||
|
Liabilities settled or disposed of
|
(282 | ) | (58 | ) | ||||
|
Accretion expense
|
78 | 72 | ||||||
|
Revisions
|
(6 | ) | (23 | ) | ||||
|
Foreign currency translation
|
16 | 78 | ||||||
|
Asset retirement obligations at December 31
|
1,358 | 1,297 | ||||||
|
Less: current obligations
|
155 | 63 | ||||||
|
Long-term obligations at December 31
|
$ | 1,203 | $ | 1,234 | ||||
| 9. | Long-Term Debt |
Long-term debt at December 31 consists of the following:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Fixed-rate notes:
|
||||||||
|
6.7% due 2011
|
$ | — | $ | 116 | ||||
|
7.0% due 2014
|
250 | 250 | ||||||
|
8.1% due 2019
|
997 | 997 | ||||||
|
7.9% due 2029
|
695 | 694 | ||||||
|
7.3% due 2031
|
746 | 746 | ||||||
|
7.1% due 2033
|
598 | 598 | ||||||
|
6.0% due 2040
|
744 | 744 | ||||||
|
5.6% due 2041
|
1,241 | — | ||||||
|
Total fixed-rate notes
|
5,271 | 4,145 | ||||||
|
Other fixed-rate notes, weighted average rate 8.4%, due through
2023
|
133 | 154 | ||||||
|
Project lease financing, weighted average rate 5.1%, due through
2014
|
102 | 113 | ||||||
|
Pollution control revenue bonds, weighted average rate 5.9%, due
through 2034
|
53 | 53 | ||||||
|
Other debt
|
10 | 2 | ||||||
| 5,569 | 4,467 | |||||||
|
Less: amount included in current maturities
|
32 | 148 | ||||||
|
Total
|
$ | 5,537 | $ | 4,319 | ||||
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In August 2010, the Corporation issued $1,250 million of
30 year fixed-rate notes with a coupon of 5.6% scheduled to
mature in 2041. The proceeds were used to purchase additional
acreage in the Bakken and additional interests in the Valhall
and Hod fields.
In December 2009, the Corporation issued $750 million of
30 year fixed-rate notes with a coupon of 6% and tendered
for the $662 million of notes due in August 2011. The
Corporation completed the purchase of $546 million of the
2011 notes in 2009 and recorded a charge of $54 million
($34 million after income taxes). The remaining
$116 million of the 2011 notes, classified as short-term
debt and current maturities of long term debt at
December 31, 2009, was redeemed in January 2010, resulting
in a charge of $11 million ($7 million after income
taxes). The charges resulting from the repurchase of the notes
are reported in Other, net within the Statement of Consolidated
Income.
In February 2009, the Corporation issued $250 million of
5 year fixed-rate notes with a coupon of 7% and
$1 billion of 10 year fixed-rate 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.
The aggregate long-term debt maturing during the next five years
is as follows (in millions): 2011 — $32 (included in
short-term debt and current maturities of long-term debt);
2012 — $35; 2013 — $37; 2014 —
$341 and 2015 — $4.
At December 31, 2010, the Corporation’s fixed-rate
notes have a principal amount of $5,300 million
($5,271 million net of unamortized discount). Interest
rates on the outstanding fixed rate notes have a weighted
average rate of 6.9%.
The Corporation has a $3 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, 2010, the Corporation has
available capacity on the facility of $3 billion.
Borrowings under the facility bear interest at 0.4% above the
London Interbank Offered Rate. A facility fee of 0.1% per annum
is also 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 to borrow or issue letters of credit of up to
$1 billion, subject to the availability of sufficient
levels of eligible receivables. At December 31, 2010,
outstanding letters of credit under this facility were
collateralized by a total of $1,194 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’s long-term debt agreements contain a
financial covenant that restricts the amount of total borrowings
and secured debt. At December 31, 2010, the Corporation is
permitted to borrow up to an additional $22.4 billion for
the construction or acquisition of assets. The Corporation has
the ability to borrow up to an additional $4.4 billion of
secured debt at December 31, 2010.
63
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Outstanding letters of credit at December 31 were as follows:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Asset-backed credit facility
|
$ | 400 | $ | 500 | ||||
|
Committed lines*
|
1,161 | 1,155 | ||||||
|
Uncommitted lines*
|
521 | 1,192 | ||||||
|
Total
|
$ | 2,082 | $ | 2,847 | ||||
| * | Committed and uncommitted lines have expiration dates through 2013. |
Of the total letters of credit outstanding at December 31,
2010, $81 million relates to contingent liabilities and the
remaining $2,001 million relates to liabilities recorded on
the balance sheet.
The total amount of interest paid (net of amounts capitalized)
was $319 million, $335 million and $266 million
in 2010, 2009 and 2008, respectively. The Corporation
capitalized interest of $5 million, $6 million and
$7 million in 2010, 2009, and 2008, respectively.
| 10. | 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 | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Stock options
|
$ | 52 | $ | 58 | $ | 51 | $ | 32 | $ | 36 | $ | 31 | ||||||||||||
|
Restricted stock
|
60 | 70 | 68 | 37 | 44 | 43 | ||||||||||||||||||
|
Total
|
$ | 112 | $ | 128 | $ | 119 | $ | 69 | $ | 80 | $ | 74 | ||||||||||||
Based on restricted stock and stock option awards outstanding at
December 31, 2010, unearned compensation expense, before
income taxes, will be recognized in future years as follows (in
millions): 2011 — $77, 2012 — $40 and
2013 — $4.
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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, 2008
|
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 | ||||||||||||
|
Granted
|
2,792 | 60.12 | 952 | 60.04 | ||||||||||||
|
Exercised
|
(1,080 | ) | 42.37 | — | — | |||||||||||
|
Vested
|
— | — | (880 | ) | 55.42 | |||||||||||
|
Forfeited
|
(394 | ) | 65.04 | (182 | ) | 65.56 | ||||||||||
|
Outstanding at December 31, 2010
|
13,420 | 55.73 | 2,838 | 67.32 | ||||||||||||
|
Exercisable at December 31, 2008
|
4,522 | $ | 36.95 | |||||||||||||
|
Exercisable at December 31, 2009
|
6,636 | 46.11 | ||||||||||||||
|
Exercisable at December 31, 2010
|
8,079 | 51.73 | ||||||||||||||
The table below summarizes information regarding the outstanding
and exercisable stock options as of December 31, 2010:
| 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
|
1,935 | 3 | $ | 26.62 | 1,935 | $ | 26.62 | |||||||||||||
|
$40.01 – $50.00
|
1,708 | 5 | 49.19 | 1,705 | 49.20 | |||||||||||||||
|
$50.01 – $60.00
|
4,867 | 7 | 55.09 | 2,914 | 54.21 | |||||||||||||||
|
$60.01 – $80.00
|
2,753 | 9 | 60.32 | 80 | 65.31 | |||||||||||||||
|
$80.01 – $120.00
|
2,157 | 7 | 82.58 | 1,445 | 82.58 | |||||||||||||||
| 13,420 | 7 | 55.73 | 8,079 | 51.73 | ||||||||||||||||
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, 2010 was $292 million
65
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and $209 million, respectively. At December 31, 2010,
assuming forfeitures of 2% per year, 13,200,000 outstanding
options are expected to vest at a weighted average exercise
price of $55.66 per share. At December 31, 2010, the
weighted average remaining term of exercisable options was six
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:
| 2010 | 2009 | 2008 | ||||||||||
|
Risk free interest rate
|
2.14 | % | 1.80 | % | 2.70 | % | ||||||
|
Stock price volatility
|
.390 | .390 | .294 | |||||||||
|
Dividend yield
|
.67 | % | .70 | % | .50 | % | ||||||
|
Expected term in years
|
4.5 | 4.5 | 5.0 | |||||||||
|
Weighted average fair value per option granted
|
$ | 20.18 | $ | 18.47 | $ | 24.09 | ||||||
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 and in May 2010 approved an amendment to the 2008 Long-Term
Incentive Plan. The Corporation also has stock options
outstanding under a former plan. At December 31, 2010, the
number of common shares reserved for issuance under the 2008
Long-Term Incentive Plan, as amended, is as follows (in
thousands):
|
Total common shares reserved for issuance
|
17,178 | |||
|
Less: stock options outstanding
|
5,671 | |||
|
Available for future awards of restricted stock and stock options
|
11,507 | |||
| 11. | Foreign Currency Translation |
Foreign currency gains (losses) before income taxes amounted to
$(5) million in 2010, $20 million in 2009 and
$(212) million in 2008. 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 an increase to stockholders’ equity of
$12 million at December 31, 2010 and a reduction to
stockholders’ equity of $18 million at
December 31, 2009.
| 12. | 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, which provides incremental
payments 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.
66
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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 | ||||||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Change in benefit obligation
|
||||||||||||||||||||||||
|
Balance at January 1
|
$ | 1,359 | $ | 1,125 | $ | 188 | $ | 165 | $ | 84 | $ | 77 | ||||||||||||
|
Service cost
|
41 | 34 | 8 | 6 | 5 | 3 | ||||||||||||||||||
|
Interest cost
|
78 | 72 | 8 | 11 | 4 | 4 | ||||||||||||||||||
|
Actuarial (gain) loss
|
75 | 139 | 7 | 43 | 18 | 3 | ||||||||||||||||||
|
Benefit payments
|
(46 | ) | (43 | ) | (2 | ) | (2 | ) | (4 | ) | (3 | ) | ||||||||||||
|
Plan settlements*
|
— | — | (17 | ) | (35 | ) | — | — | ||||||||||||||||
|
Foreign currency exchange rate changes
|
(10 | ) | 32 | — | — | — | — | |||||||||||||||||
|
Balance at December 31
|
1,497 | 1,359 | 192 | 188 | 107 | 84 | ||||||||||||||||||
|
Change in fair value of plan assets
|
||||||||||||||||||||||||
|
Balance at January 1
|
1,072 | 745 | — | — | — | — | ||||||||||||||||||
|
Actual return on plan assets
|
155 | 161 | — | — | — | — | ||||||||||||||||||
|
Employer contributions
|
192 | 183 | 20 | 37 | 4 | 3 | ||||||||||||||||||
|
Benefit payments
|
(46 | ) | (43 | ) | (20 | ) | (37 | ) | (4 | ) | (3 | ) | ||||||||||||
|
Foreign currency exchange rate changes
|
(8 | ) | 26 | — | — | — | — | |||||||||||||||||
|
Balance at December 31
|
1,365 | 1,072 | — | — | — | — | ||||||||||||||||||
|
Funded status (plan assets less than benefit obligations) at
December 31
|
(132 | ) | (287 | ) | (192 | )** | (188 | )** | (107 | ) | (84 | ) | ||||||||||||
|
Unrecognized net actuarial losses
|
460 | 495 | 83 | 92 | 32 | 16 | ||||||||||||||||||
|
Net amount recognized
|
$ | 328 | $ | 208 | $ | (109 | ) | $ | (96 | ) | $ | (75 | ) | $ | (68 | ) | ||||||||
| * | The Corporation recorded charges related to plan settlements of $8 million ($5 million after income taxes) in 2010 and $17 million ($10 million after income taxes) in 2009 due to employee retirements. | |
| ** | The trust established by the Corporation for the supplemental plan held assets valued at $21 million at December 31, 2010 and $40 million at December 31, 2009. |
Amounts recognized in the consolidated balance sheet at December
31 consist of the following:
|
Funded
|
Unfunded
|
Postretirement
|
||||||||||||||||||||||
| Pension Plans | Pension Plan | Medical Plan | ||||||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Accrued benefit liability
|
$ | (132 | ) | $ | (287 | ) | $ | (192 | ) | $ | (188 | ) | $ | (107 | ) | $ | (84 | ) | ||||||
|
Accumulated other comprehensive loss, pre-tax*
|
460 | 495 | 83 | 92 | 32 | 16 | ||||||||||||||||||
|
Net amount recognized
|
$ | 328 | $ | 208 | $ | (109 | ) | $ | (96 | ) | $ | (75 | ) | $ | (68 | ) | ||||||||
| * | The after-tax reduction to equity recorded in Accumulated other comprehensive income (loss) was $385 million at December 31, 2010 and $413 million at December 31, 2009. |
67
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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 $1,355 million at
December 31, 2010 and $1,229 million at
December 31, 2009. The accumulated benefit obligation for
the unfunded defined benefit pension plan was $176 million
at December 31, 2010 and $172 million at
December 31, 2009.
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 | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||
|
Service cost
|
$ | 49 | $ | 40 | $ | 42 | $ | 5 | $ | 3 | $ | 3 | ||||||||||||
|
Interest cost
|
86 | 83 | 80 | 4 | 4 | 4 | ||||||||||||||||||
|
Expected return on plan assets
|
(86 | ) | (59 | ) | (80 | ) | — | — | — | |||||||||||||||
|
Amortization of unrecognized net actuarial loss
|
48 | 65 | 19 | 1 | — | — | ||||||||||||||||||
|
Settlement loss
|
8 | 17 | — | — | — | — | ||||||||||||||||||
|
Net periodic benefit cost
|
$ | 105 | $ | 146 | $ | 61 | $ | 10 | $ | 7 | $ | 7 | ||||||||||||
The Corporation’s 2011 pension and postretirement medical
expense is estimated to be approximately $90 million, of
which approximately $45 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:
| 2010 | 2009 | 2008 | ||||||||||
|
Weighted-average assumptions used to determine benefit
obligations at December 31
|
||||||||||||
|
Discount rate
|
5.3 | % | 5.8 | % | 6.3 | % | ||||||
|
Rate of compensation increase
|
4.4 | 4.3 | 4.4 | |||||||||
|
Weighted-average assumptions used to determine net benefit cost
for years ended December 31
|
||||||||||||
|
Discount rate
|
5.8 | 6.3 | 6.3 | |||||||||
|
Expected return on plan assets
|
7.5 | 7.5 | 7.5 | |||||||||
|
Rate of compensation increase
|
4.3 | 4.4 | 4.4 | |||||||||
The actuarial assumptions used by the Corporation’s
postretirement medical plan were as follows:
| 2010 | 2009 | 2008 | ||||||||||
|
Assumptions used to determine benefit obligations at December 31
|
||||||||||||
|
Discount rate
|
4.8 | % | 5.4 | % | 6.3 | % | ||||||
|
Initial health care trend rate
|
8.0 | % | 8.0 | % | 9.0 | % | ||||||
|
Ultimate trend rate
|
5.0 | % | 4.5 | % | 4.5 | % | ||||||
|
Year in which ultimate trend rate is reached
|
2017 | 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 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
68
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 tables provide the fair value of the financial
assets of the funded pension plans as of December 31, 2010
and 2009 in accordance with the fair value measurement hierarchy
described in Note 1, Summary of Significant Accounting
Policies:
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
|
December 31, 2010
|
||||||||||||||||
|
Cash and short-term investment funds
|
$ | 5 | $ | 31 | $ | — | $ | 36 | ||||||||
|
Equities:
|
||||||||||||||||
|
U.S. equities (domestic)
|
444 | — | — | 444 | ||||||||||||
|
International equities
(non-U.S.)
|
53 | 121 | — | 174 | ||||||||||||
|
Global equities (domestic and
non-U.S.)
|
18 | 140 | — | 158 | ||||||||||||
|
Fixed income:
|
||||||||||||||||
|
Treasury and government issued(a)
|
— | 98 | 3 | 101 | ||||||||||||
|
Government related(b)
|
— | 14 | 3 | 17 | ||||||||||||
|
Mortgage-backed securities(c)
|
— | 61 | — | 61 | ||||||||||||
|
Corporate
|
— | 93 | 1 | 94 | ||||||||||||
|
Other:
|
||||||||||||||||
|
Hedge funds
|
— | — | 187 | 187 | ||||||||||||
|
Private equity funds
|
— | — | 40 | 40 | ||||||||||||
|
Real estate funds
|
7 | — | 32 | 39 | ||||||||||||
|
Diversified commodities funds
|
— | 14 | — | 14 | ||||||||||||
| $ | 527 | $ | 572 | $ | 266 | $ | 1,365 | |||||||||
69
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
|
December 31, 2009
|
||||||||||||||||
|
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 fund values reflect the NAV per fund
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
responsible for 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.
70
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following tables provide changes in financial assets that
are measured at fair value based on Level 3 inputs that are
held by institutional funds classified as:
|
Private
|
Real
|
|||||||||||||||||||
|
Fixed
|
Hedge
|
Equity
|
Estate
|
|||||||||||||||||
| Income* | Funds | Funds | Funds | Total | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
Balance at January 1, 2010
|
$ | 8 | $ | 143 | $ | 29 | $ | 14 | $ | 194 | ||||||||||
|
Actual return on plan assets:
|
||||||||||||||||||||
|
Related to assets held at December 31, 2010
|
— | 6 | 1 | 1 | 8 | |||||||||||||||
|
Related to assets sold during 2010
|
— | — | — | — | — | |||||||||||||||
|
Purchases, sales or other settlements
|
1 | 38 | 10 | 17 | 66 | |||||||||||||||
|
Net transfers in (out) of Level 3
|
(2 | ) | — | — | — | (2 | ) | |||||||||||||
|
Balance at December 31, 2010
|
$ | 7 | $ | 187 | $ | 40 | $ | 32 | $ | 266 | ||||||||||
|
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 (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
$190 million to its funded pension plans in 2011.
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):
|
2011
|
$ | 81 | ||
|
2012
|
79 | |||
|
2013
|
88 | |||
|
2014
|
91 | |||
|
2015
|
98 | |||
|
Years 2016 to 2020
|
612 |
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 contributions. The Corporation recorded
expense of $24 million in 2010 and 2009, and
$22 million in 2008 for contributions to these plans.
71
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 13. | Income Taxes |
The provision for (benefit from) income taxes consisted of:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
United States Federal
|
||||||||||||
|
Current
|
$ | 151 | $ | 39 | $ | 10 | ||||||
|
Deferred
|
(309 | ) | (284 | ) | (140 | ) | ||||||
|
State
|
46 | (15 | ) | 10 | ||||||||
| (112 | ) | (260 | ) | (120 | ) | |||||||
|
Foreign
|
||||||||||||
|
Current
|
1,515 | 1,143 | 2,377 | |||||||||
|
Deferred
|
(230 | ) | (168 | ) | 87 | |||||||
| 1,285 | 975 | 2,464 | ||||||||||
|
Adjustment of deferred tax liability for foreign income tax rate
change
|
— | — | (4 | ) | ||||||||
|
Total provision for income taxes
|
$ | 1,173 | $ | 715 | $ | 2,340 | ||||||
Income (loss) before income taxes consisted of the following:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
United States*
|
$ | (108 | ) | $ | (711 | ) | $ | (349 | ) | |||
|
Foreign**
|
3,419 | 2,233 | 5,046 | |||||||||
|
Total income before income taxes
|
$ | 3,311 | $ | 1,522 | $ | 4,697 | ||||||
| * | 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. |
72
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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:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Deferred tax liabilities
|
||||||||
|
Property, plant and equipment and investments
|
$ | 3,853 | $ | 3,021 | ||||
|
Deferred taxes on undistributed earnings of foreign subsidiaries
|
— | 174 | ||||||
|
Other
|
52 | 13 | ||||||
|
Total deferred tax liabilities
|
3,905 | 3,208 | ||||||
|
Deferred tax assets
|
||||||||
|
Net operating loss carryforwards
|
896 | 529 | ||||||
|
Tax credit carryforwards
|
244 | 860 | ||||||
|
Property, plant and equipment
|
1,679 | 1,575 | ||||||
|
Accrued liabilities
|
391 | 459 | ||||||
|
Asset retirement obligations
|
369 | 484 | ||||||
|
Other
|
302 | 339 | ||||||
|
Total deferred tax assets
|
3,881 | 4,246 | ||||||
|
Valuation allowance
|
(444 | ) | (500 | ) | ||||
|
Total deferred tax assets, net
|
3,437 | 3,746 | ||||||
|
Net deferred tax assets (liabilities)
|
$ | (468 | ) | $ | 538 | |||
Net deferred tax assets in the foregoing table include the
deferral of the tax consequences, including the utilization of
net operating loss carryforwards and tax credits in the United
States during 2009 and 2010, resulting from intercompany
transactions eliminated in consolidation related to transfers of
property, plant and equipment remaining within the consolidated
group. At December 31, 2010, the Corporation has recognized
a gross deferred tax asset, before application of valuation
allowance, of $896 million related to net operating loss
carryforwards. This is comprised of approximately
$101 million attributable to United States federal income
tax which begin to expire in 2020, $165 million
attributable to various states which begin to expire in 2011,
and $630 million attributable to foreign jurisdictions
which begin to expire in 2020. At December 31, 2010, the
Corporation has federal, state and foreign alternative minimum
tax credit carryforwards of approximately $126 million,
which can be carried forward indefinitely and approximately
$1 million of other business credit carryforwards. Foreign
tax credit carryforwards, which expire in 2019, total
$117 million.
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:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Other current assets
|
$ | 386 | $ | 372 | ||||
|
Deferred income taxes (long-term asset)
|
2,167 | 2,409 | ||||||
|
Accrued liabilities
|
(26 | ) | (21 | ) | ||||
|
Deferred income taxes (long-term liability)
|
(2,995 | ) | (2,222 | ) | ||||
|
Net deferred tax assets (liabilities)
|
$ | (468 | ) | $ | 538 | |||
73
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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:
| 2010 | 2009 | 2008 | ||||||||||
|
United States statutory rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
Effect of foreign operations
|
9.4 | 15.2 | 12.7 | |||||||||
|
State income taxes, net of Federal income tax
|
0.9 | (1.2 | ) | 0.1 | ||||||||
|
Gains on asset sales
|
(10.4 | ) | — | — | ||||||||
|
Impairment of equity investment
|
3.1 | — | — | |||||||||
|
Other
|
(2.6 | ) | (2.0 | ) | 2.0 | |||||||
|
Total
|
35.4 | % | 47.0 | % | 49.8 | % | ||||||
Below is a reconciliation of the beginning and ending amount of
unrecognized tax benefits:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Balance at January 1
|
$ | 271 | $ | 175 | ||||
|
Additions based on tax positions taken in the current year
|
152 | 106 | ||||||
|
Additions based on tax positions of prior years
|
57 | 25 | ||||||
|
Reductions based on tax positions of prior years
|
(2 | ) | (3 | ) | ||||
|
Reductions due to settlements with taxing authorities
|
(77 | ) | (20 | ) | ||||
|
Reductions due to lapse of statutes of limitation
|
(1 | ) | (12 | ) | ||||
|
Balance at December 31
|
$ | 400 | $ | 271 | ||||
At December 31, 2010, the unrecognized tax benefits include
$294 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 $40 million
to $50 million due to settlements with taxing authorities.
The Corporation had accrued interest and penalties related to
unrecognized tax benefits of approximately $16 million as
of December 31, 2010 and approximately $17 million as
of December 31, 2009.
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 $4.5 billion at
December 31, 2010. If these earnings were not indefinitely
reinvested, a deferred tax liability of approximately
$1.6 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 2005.
Income taxes paid (net of refunds) in 2010, 2009 and 2008
amounted to $1,450 million, $1,177 million and
$2,420 million, respectively.
74
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 14. | Outstanding and Weighted Average Common Shares |
The following table provides the changes in the
Corporation’s outstanding common shares:
| 2010 | 2009 | 2008 | ||||||||||
| (Thousands of shares) | ||||||||||||
|
Balance at January 1
|
327,229 | 326,133 | 320,600 | |||||||||
|
Issued for an acquisition*
|
8,602 | — | — | |||||||||
|
Activity related to restricted common stock awards, net
|
770 | 680 | 1,148 | |||||||||
|
Employee stock options
|
1,080 | 416 | 3,852 | |||||||||
|
Conversion of preferred stock
|
— | — | 533 | |||||||||
|
Balance at December 31
|
337,681 | 327,229 | 326,133 | |||||||||
| * | See Note 2, Acquisitions and Divestitures. |
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 approximately 533,000 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:
| 2010 | 2009 | 2008 | ||||||||||
| (Thousands of shares) | ||||||||||||
|
Common shares — basic
|
325,999 | 323,890 | 320,803 | |||||||||
|
Effect of dilutive securities
|
||||||||||||
|
Stock options
|
829 | 836 | 2,870 | |||||||||
|
Restricted common stock
|
1,449 | 1,239 | 1,815 | |||||||||
|
Convertible preferred stock
|
— | — | 359 | |||||||||
|
Common shares — diluted
|
328,277 | 325,965 | 325,847 | |||||||||
The calculation of weighted average common shares excludes the
effect of 5,157,000, 4,050,000 and 425,000
out-of-the-money
options for 2010, 2009 and 2008, respectively. Cash dividends on
common stock totaled $0.40 per share ($0.10 per quarter) during
2010, 2009 and 2008.
75
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 15. | 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, 2010, 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):
|
2011
|
$ | 410 | ||
|
2012
|
421 | |||
|
2013
|
419 | |||
|
2014
|
377 | |||
|
2015
|
181 | |||
|
Remaining years
|
1,269 | |||
|
Total minimum lease payments
|
3,077 | |||
|
Less: income from subleases
|
58 | |||
|
Net minimum lease payments
|
$ | 3,019 | ||
Operating lease expenses for drilling rigs used to drill
development wells and successful exploration wells are
capitalized.
Rental expense was as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Total rental expense
|
$ | 273 | $ | 266 | $ | 270 | ||||||
|
Less: income from subleases
|
13 | 11 | 12 | |||||||||
|
Net rental expense
|
$ | 260 | $ | 255 | $ | 258 | ||||||
| 16. | 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. In the
disclosures that follow these activities are referred to as
energy marketing and corporate risk management activities. 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, electricity, refined products, and
energy-related securities.
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
76
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
amounts of both long and short positions are presented in the
volume tables below. These amounts include long and short
positions that offset in closed positions 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 and pipeline capacity, 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, | ||||||||
| 2010 | 2009 | |||||||
|
Commodity Contracts
|
||||||||
|
Crude oil and refined products (millions of barrels)
|
30 | 34 | ||||||
|
Natural gas (millions of mcf)
|
2,210 | 1,876 | ||||||
|
Electricity (millions of megawatt hours)
|
301 | 166 | ||||||
The changes in fair value of certain 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 related to these
energy marketing activities are recognized in Cost of products
sold. Net realized and unrealized pre-tax gains on derivative
contracts not designated as hedges amounted to $247 million
in 2010 and $102 million in 2009.
At December 31, 2010, 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 one year or less. For contracts outstanding at
December 31, 2010, the maximum duration was approximately
three 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 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, 2010, the after-tax deferred losses
relating to energy marketing activities recorded in Accumulated
other comprehensive income were $147 million
($303 million at December 31, 2009). The Corporation
estimates that approximately $104 million of this amount
will be reclassified into earnings over the next twelve months.
During 2010, 2009 and 2008, the Corporation reclassified
after-tax income (losses) from Accumulated other comprehensive
income of $(318) million, $(596) million and
$112 million, respectively. The amount of gain (loss) from
hedge ineffectiveness reflected in earnings in 2010, 2009 and
2008 was $2 million, $(2) million and $1 million.
The fair value of energy marketing cash flow hedge positions
decreased by $164 million in 2010, $564 million in
2009 and $255 million in 2008. 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.
Corporate Risk Management:
Corporate
risk management activities include transactions designed to
reduce risk in the selling prices of crude oil, refined products
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 fix the
forward selling price of a portion of the Corporation’s
crude oil, refined products or natural gas
77
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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. These forward contracts comprise various
currencies including the British Pound and Thai Baht. Interest
rate swaps may be used to convert interest payments on certain
long-term debt from fixed to floating rates.
The table below shows the gross volume of Corporate risk
management derivative instruments outstanding:
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
|
Commodity contracts, primarily crude oil (millions of barrels)*
|
35 | 54 | ||||||
|
Foreign exchange contracts (millions of U.S. Dollars)
|
1,025 | 872 | ||||||
|
Interest rate swaps (millions of U.S. Dollars)
|
310 | — | ||||||
| * | Principally reflects volumes associated with the offsetting crude oil 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, 2010. Hedging activities decreased Exploration
and Production Sales and other operating revenue by
$338 million in 2010, $337 million in 2009 and
$423 million in 2008.
At December 31, 2010, the after-tax deferred losses in
Accumulated other comprehensive income relating to the closed
Brent crude oil hedges were $638 million ($941 million
at December 31, 2009). The Corporation estimates that
approximately $330 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.
At December 31, 2010, the Corporation had interest rate
swaps with a gross notional amount of $310 million, which
were designated as fair value hedges. Changes in the fair value
of interest rate swaps and the hedged fixed-rate debt are
recorded in Interest expense. For the year ended
December 31, 2010, the Corporation recorded an increase of
$8 million in the fair value of interest rate swaps and a
corresponding increase in the carrying value of the hedged
fixed-rate debt.
Foreign exchange contracts are not designated as hedges. Gains
or losses on foreign exchange contracts are recognized
immediately in Other, net in Revenues and non-operating income.
Net pre-tax gains (losses) on derivative contracts used for
Corporate risk management and not designated as hedges amounted
to the following:
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Commodity
|
$ | (7 | ) | $ | 9 | |||
|
Foreign exchange
|
(7 | ) | 86 | |||||
|
Total
|
$ | (14 | ) | $ | 95 | |||
78
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 derivative instruments
outstanding relating to trading activities:
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
|
Commodity Contracts
|
||||||||
|
Crude oil and refined products (millions of barrels)
|
3,328 | 2,251 | ||||||
|
Natural gas (millions of mcf)
|
4,699 | 6,927 | ||||||
|
Electricity (millions of megawatt hours)
|
79 | 6 | ||||||
|
Other Contracts (millions of U.S. Dollars)
|
||||||||
|
Interest rate
|
205 | 495 | ||||||
|
Foreign exchange
|
506 | 335 | ||||||
Pre-tax gains (losses) recorded in Sales and other operating
revenues from trading activities amounted to the following:
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Commodity
|
$ | 88 | $ | 196 | ||||
|
Foreign exchange
|
5 | 23 | ||||||
|
Interest rate and other
|
10 | 17 | ||||||
|
Total
|
$ | 103 | $ | 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).
When Level 1 inputs are available within a particular
market, those inputs are selected for determination of fair
value over Level 2 or 3 inputs in the same market. To value
Level 2 and 3 derivatives the Corporation uses observable
inputs for similar instruments that are available from
exchanges, pricing services or broker quotes. These observable
inputs may be supplemented with other methods, including
internal extrapolation, that result in the most representative
prices for instruments with similar characteristics. 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 hierarchy.
79
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table provides the Corporation’s net
financial assets and (liabilities) that are measured at fair
value based on this hierarchy:
|
Collateral and
|
||||||||||||||||||||
|
counterparty
|
||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | netting | Balance | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
December 31, 2010
|
||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Derivative contracts
|
||||||||||||||||||||
|
Commodity
|
$ | 65 | $ | 1,308 | $ | 883 | $ | (304 | ) | $ | 1,952 | |||||||||
|
Foreign exchange
|
— | 1 | — | — | 1 | |||||||||||||||
|
Other
|
— | 17 | — | — | 17 | |||||||||||||||
|
Collateral and counterparty netting
|
(1 | ) | (274 | ) | (19 | ) | (213 | ) | (507 | ) | ||||||||||
|
Total derivative contracts
|
64 | 1,052 | 864 | (517 | ) | 1,463 | ||||||||||||||
|
Other assets measured at fair value on a recurring basis
|
20 | 49 | 3 | — | 72 | |||||||||||||||
|
Total assets
|
$ | 84 | $ | 1,101 | $ | 867 | $ | (517 | ) | $ | 1,535 | |||||||||
|
Liabilities
|
||||||||||||||||||||
|
Derivative contracts
|
||||||||||||||||||||
|
Commodity
|
$ | (324 | ) | $ | (2,519 | ) | $ | (474 | ) | $ | 304 | $ | (3,013 | ) | ||||||
|
Foreign exchange
|
— | (12 | ) | — | — | (12 | ) | |||||||||||||
|
Other
|
— | (10 | ) | — | — | (10 | ) | |||||||||||||
|
Collateral and counterparty netting
|
1 | 274 | 19 | 34 | 328 | |||||||||||||||
|
Total derivative contracts
|
(323 | ) | (2,267 | ) | (455 | ) | 338 | (2,707 | ) | |||||||||||
|
Other liabilities measured at fair value on a recurring basis
|
— | — | — | — | — | |||||||||||||||
|
Total liabilities
|
$ | (323 | ) | $ | (2,267 | ) | $ | (455 | ) | $ | 338 | $ | (2,707 | ) | ||||||
80
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
|
Collateral and
|
||||||||||||||||||||
|
counterparty
|
||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | netting | Balance | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
December 31, 2009
|
||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Derivative contracts
|
||||||||||||||||||||
|
Commodity
|
$ | 46 | $ | 1,137 | $ | 119 | $ | (40 | ) | $ | 1,262 | |||||||||
|
Other
|
— | 3 | — | — | 3 | |||||||||||||||
|
Collateral and counterparty netting
|
— | (1 | ) | — | (326 | ) | (327 | ) | ||||||||||||
|
Total derivative contracts
|
46 | 1,139 | 119 | (366 | ) | 938 | ||||||||||||||
|
Other assets measured at fair value on a recurring basis
|
37 | 21 | 5 | — | 63 | |||||||||||||||
|
Total assets
|
$ | 83 | $ | 1,160 | $ | 124 | $ | (366 | ) | $ | 1,001 | |||||||||
|
Liabilities
|
||||||||||||||||||||
|
Derivative contracts
|
||||||||||||||||||||
|
Commodity
|
$ | (151 | ) | $ | (2,880 | ) | $ | (36 | ) | $ | 40 | $ | (3,027 | ) | ||||||
|
Foreign exchange
|
— | (23 | ) | — | — | (23 | ) | |||||||||||||
|
Other
|
— | (8 | ) | — | — | (8 | ) | |||||||||||||
|
Collateral and counterparty netting
|
— | 1 | — | 280 | 281 | |||||||||||||||
|
Total derivative contracts
|
(151 | ) | (2,910 | ) | (36 | ) | 320 | (2,777 | ) | |||||||||||
|
Other liabilities measured at fair value on a recurring basis
|
— | (66 | ) | (4 | ) | — | (70 | ) | ||||||||||||
|
Total liabilities
|
$ | (151 | ) | $ | (2,976 | ) | $ | (40 | ) | $ | 320 | $ | (2,847 | ) | ||||||
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, | ||||||||
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Balance at beginning of period
|
$ | 84 | $ | 149 | ||||
|
Unrealized gains (losses)
|
||||||||
|
Included in earnings
|
169 | 103 | ||||||
|
Included in other comprehensive income
|
101 | 15 | ||||||
|
Purchases, sales or other settlements during the period
|
83 | (144 | ) | |||||
|
Transfers into Level 3
|
30 | — | ||||||
|
Transfers out of Level 3
|
(55 | ) | (39 | ) | ||||
|
Balance at end of period
|
$ | 412 | $ | 84 | ||||
Effective January 1, 2010, the Corporation’s policy is
to recognize transfers in and transfers out as of the end of
each reporting period. During the year ended December 31,
2010, transfers into Level 1 and Level 2 were net
assets of $14 million and $312 million, respectively,
and transfers out of Level 1 and Level 2 were net
assets of $28 million and net liabilities of
$329 million, respectively. Transfers into Level 1 and
2 from Levels 2 and 3, respectively
81
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CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
primarily resulted from instruments that became more actively
traded as they moved closer to maturity. Transfers into
Level 2 and 3 from Levels 1 and 2, respectively were
due to the increased significance of the lower level inputs to
the instrument’s fair value.
In addition to the financial assets and liabilities disclosed in
the tables above, the Corporation had other short-term financial
instruments, primarily cash equivalents and accounts receivable
and payable, for which the carrying value approximated their
fair value at December 31, 2010 and December 31, 2009.
Fixed-rate, long-term debt had a carrying value of
$5,569 million compared with a fair value of
$6,353 million at December 31, 2010, and a carrying
value of $4,467 million compared with a fair value of
$5,073 million at December 31, 2009.
The table below reflects the gross and net fair values of the
Corporation’s risk management and trading derivative
instruments:
|
Accounts
|
Accounts
|
|||||||
| Receivable | Payable | |||||||
| (Millions of dollars) | ||||||||
|
December 31, 2010
|
||||||||
|
Derivative contracts designated as hedging instruments
|
||||||||
|
Commodity
|
$ | 225 | $ | (483 | ) | |||
|
Other
|
10 | (2 | ) | |||||
|
Total derivative contracts designated as hedging instruments
|
235 | (485 | ) | |||||
|
Derivative contracts not designated as hedging instruments*
|
||||||||
|
Commodity
|
11,581 | (12,383 | ) | |||||
|
Foreign exchange
|
7 | (19 | ) | |||||
|
Other
|
31 | (32 | ) | |||||
|
Total derivative contracts not designated as hedging instruments
|
11,619 | (12,434 | ) | |||||
|
Gross fair value of derivative contracts
|
11,854 | (12,919 | ) | |||||
|
Master netting arrangements
|
(10,178 | ) | 10,178 | |||||
|
Cash collateral (received) posted
|
(213 | ) | 34 | |||||
|
Net fair value of derivative contracts
|
$ | 1,463 | $ | (2,707 | ) | |||
|
December 31, 2009
|
||||||||
|
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. |
82
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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.
Credit Risk:
The Corporation is exposed
to credit risks that may at times be concentrated with certain
counterparties, groups of counterparties or customers. Accounts
receivable are generated from a diverse domestic and
international customer base. The Corporation’s net
receivables at December 31, 2010 are concentrated with the
following counterparty and customer industry segments:
Integrated Oil Companies — 22%, Government
Entities — 14%, Manufacturing — 10% and
Services — 10%. 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 to the fair value of derivatives executed
with the same counterparty. At December 31, 2010 and 2009,
the Corporation held cash from counterparties of
$213 million and $317 million, respectively. The
Corporation posted cash to counterparties at December 31,
2010 and 2009 of $34 million and $269 million,
respectively.
At December 31, 2010, the Corporation had a total of
$2,082 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, 2010, the net liability related to
derivatives with contingent collateral provisions was
approximately $1,692 million before cash collateral posted
of approximately $16 million. At December 31, 2010,
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, 2010, the Corporation would be required to
post additional collateral of approximately $385 million.
| 17. | Guarantees and Contingencies |
At December 31, 2010, the Corporation’s guarantees
include $150 million of HOVENSA’s crude oil purchases
and $15 million of HOVENSA’s senior debt obligations.
In addition, the Corporation has $81 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
$246 million at December 31, 2010 ($236 million
at December 31, 2009). 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, 2010, the
estimated value of the purchase obligation is approximately
$190 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
2010, additional cases were settled, and three new cases were
filed. The six unresolved cases consist of five 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
83
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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. In
January 2011, HOVENSA signed a Consent Decree with EPA to
resolve its claims. Under the terms of the Consent Decree,
HOVENSA will pay a penalty of approximately $5 million and
spend approximately $700 million over the next
10 years to install equipment and implement additional
operating procedures at the HOVENSA refinery to reduce
emissions. In addition, the Consent Decree requires HOVENSA to
spend approximately $5 million to fund an environmental
project to be determined at a later date by the Virgin Islands
and $500,000 to assist the Virgin Islands Water and Power
Authority with monitoring. The Consent Decree has been lodged
with the United States District Court for the Virgin Islands and
approval is pending. In addition, substantial progress has been
made towards resolving this matter for the Port Reading refining
facility, which is not expected to have a material adverse
impact on the Corporation’s financial position or results
of operations.
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,
predecessor to the Bureau of Ocean Energy Management, Regulation
and Enforcement) created regulations that included pricing
requirements to qualify for the royalty relief provided in the
Act. During the period from 2003 to 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 from time to time involved in other judicial
and administrative proceedings, including proceedings relating
to other environmental matters. The Corporation cannot predict
with certainty if, how or when such proceedings will be resolved
or what the eventual relief, if any, may be, particularly for
proceedings that are in their early stages of development or
where plaintiffs seek indeterminate damages. Numerous issues may
need to be resolved, including through potentially lengthy
discovery and determination of important factual matters before
a loss or range of loss can be reasonably estimated for any
proceeding. Subject to the foregoing, in management’s
opinion, based upon currently known facts and circumstances, the
outcome of such proceedings will not have a material adverse
effect on the financial condition of the Corporation, although
the outcome of such proceedings could be material to the
Corporation’s results of operations and cash flows for a
particular period depending on, among other things, the level of
the Corporation’s net income for such period.
84
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 18. | 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, markets and trades 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:
|
Exploration
|
Marketing
|
Corporate
|
||||||||||||||
| and Production | and Refining | and Interest | Consolidated(a) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
|
2010
|
||||||||||||||||
|
Operating revenues
|
||||||||||||||||
|
Total operating revenues(b)
|
$ | 9,119 | $ | 24,885 | $ | 1 | ||||||||||
|
Less: Transfers between affiliates
|
143 | — | — | |||||||||||||
|
Operating revenues from unaffiliated customers
|
$ | 8,976 | $ | 24,885 | $ | 1 | $ | 33,862 | ||||||||
|
Net income (loss) attributable to Hess Corporation
|
$ | 2,736 | $ | (231 | ) | $ | (380 | ) | $ | 2,125 | ||||||
|
Income (loss) from equity investment in HOVENSA L.L.C.
|
$ | — | $ | (522 | ) | $ | — | $ | (522 | ) | ||||||
|
Interest expense
|
— | — | 361 | 361 | ||||||||||||
|
Depreciation, depletion and amortization
|
2,222 | 82 | 13 | 2,317 | ||||||||||||
|
Asset impairments
|
532 | — | — | 532 | ||||||||||||
|
Provision (benefit) for income taxes
|
1,417 | 4 | (248 | ) | 1,173 | |||||||||||
|
Investments in affiliates
|
57 | 386 | — | 443 | ||||||||||||
|
Identifiable assets
|
28,242 | 6,377 | 777 | 35,396 | ||||||||||||
|
Capital employed(c)
|
19,803 | 2,715 | (126 | ) | 22,392 | |||||||||||
|
Capital expenditures
|
5,394 | 82 | 16 | 5,492 | ||||||||||||
85
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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) | ||||||||||||||||
|
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 | |||||||
|
Income (loss) from equity investment in HOVENSA L.L.C.
|
$ | — | $ | (229 | ) | $ | — | $ | (229 | ) | ||||||
|
Interest expense
|
— | — | 360 | 360 | ||||||||||||
|
Depreciation, depletion and amortization
|
2,113 | 79 | 8 | 2,200 | ||||||||||||
|
Asset impairments
|
54 | — | — | 54 | ||||||||||||
|
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 | ||||||||||||
|
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 | |||||||
|
Income (loss) from equity investment in HOVENSA L.L.C.
|
$ | — | $ | 44 | $ | — | $ | 44 | ||||||||
|
Interest expense
|
— | — | 267 | 267 | ||||||||||||
|
Depreciation, depletion and amortization
|
1,922 | 74 | 3 | 1,999 | ||||||||||||
|
Asset impairments
|
30 | — | — | 30 | ||||||||||||
|
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 | ||||||||||||
| (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 $2,200 million, $2,100 million and $2,200 million in 2010, 2009 and 2008, respectively. | |
| (c) | Calculated as equity plus debt. |
86
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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, 2010:
|
Asia and
|
||||||||||||||||||||
| United States | Europe | Africa | Other | Consolidated | ||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Operating revenues
|
$ | 28,066 | $ | 2,109 | $ | 2,271 | $ | 1,416 | $ | 33,862 | ||||||||||
|
Property, plant and equipment (net)
|
8,343 | 6,764 | * | 2,573 | 3,447 | 21,127 | ||||||||||||||
|
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 | ||||||||||||||
| * | Of the total Europe property, plant and equipment (net), Norway represented $5,002 million, $2,049 million and $1,372 million in 2010, 2009 and 2008, respectively. |
| 19. | Related Party Transactions |
The following table presents the Corporation’s related
party transactions for the year-ended December 31:
| 2010 | 2009 | 2008 | ||||||||||
| (Millions of dollars) | ||||||||||||
|
Purchases of petroleum products:
|
||||||||||||
|
HOVENSA*
|
$ | 4,307 | $ | 3,659 | $ | 6,589 | ||||||
|
Sales of petroleum products and crude oil:
|
||||||||||||
|
WilcoHess
|
2,113 | 1,634 | 2,590 | |||||||||
|
HOVENSA
|
607 | 530 | 701 | |||||||||
The following table presents the Corporation’s related
party accounts receivable / (payable) at December 31:
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
WilcoHess
|
$ | 110 | $ | 82 | ||||
|
HOVENSA, net
|
(107 | ) | 36 | |||||
| * | Corporation has agreed to purchase 50% of HOVENSA’s production of refined products at market prices, after sales by HOVENSA to unaffiliated parties. |
| 20. | Subsequent Event |
In February 2011, the Corporation completed the previously
announced sale of a package of natural gas producing assets in
the United Kingdom North Sea including its interests in the
Easington Catchment Area, the Bacton Area, the Everest Field and
the Lomond Field for approximately $350 million, after
closing adjustments. The sale of the Corporation’s interest
in the CATS pipeline is expected to close in the second quarter
of 2011.
87
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HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS DATA
(Unaudited)
SUPPLEMENTARY OIL AND GAS DATA
(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 (until September 2010), 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(c) | Africa | Other | |||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Property acquisitions(a)
|
||||||||||||||||||||
|
Unproved
|
$ | 1,887 | $ | 1,849 | $ | 38 | $ | — | $ | — | ||||||||||
|
Proved
|
1,015 | 443 | 572 | — | — | |||||||||||||||
|
Exploration
|
915 | 185 | 58 | 164 | 508 | |||||||||||||||
|
Production and development capital expenditures(b)
|
2,654 | 1,088 | 850 | 289 | 427 | |||||||||||||||
|
2009
|
||||||||||||||||||||
|
Property acquisitions
|
||||||||||||||||||||
|
Unproved
|
$ | 188 | $ | 184 | $ | 2 | $ | — | $ | 2 | ||||||||||
|
Proved
|
74 | — | — | — | 74 | |||||||||||||||
|
Exploration
|
938 | 206 | 69 | 225 | 438 | |||||||||||||||
|
Production and development capital expenditures(b)
|
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(b)
|
2,867 | 1,042 | 881 | 451 | 493 | |||||||||||||||
| (a) | Includes wells, equipment and facilities acquired with proved reserves and excludes properties acquired in non-cash property exchanges. In 2010, acquisitions include $652 million, representing the non-cash portion of the purchase price for American Oil & Gas Inc., primarily through the issuance of common stock. | |
| (b) | Includes $62 million, $(9) million and $344 million in 2010, 2009 and 2008, respectively, related to the accruals and revisions for asset retirement obligations except obligations acquired in non-cash property exchanges. | |
| (c) | In 2010, costs incurred in oil and gas producing activities in Norway, excluding non-monetary exchanges, were as follows (millions of dollars): |
|
Property acquisitions(a)
|
||||
|
Unproved
|
$ | 14 | ||
|
Proved
|
572 | |||
|
Exploration
|
12 | |||
|
Production and development capital expenditures(b)
|
469 |
88
Table of Contents
Capitalized
Costs Relating to Oil and Gas Producing Activities
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions of dollars) | ||||||||
|
Unproved properties
|
$ | 3,796 | $ | 2,347 | ||||
|
Proved properties
|
3,496 | 3,121 | ||||||
|
Wells, equipment and related facilities
|
26,064 | 22,118 | ||||||
|
Total costs
|
33,356 | 27,586 | ||||||
|
Less: reserve for depreciation, depletion, amortization and
lease impairment
|
13,553 | 12,273 | ||||||
|
Net capitalized costs
|
$ | 19,803 | $ | 15,313 | ||||
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 Financial Condition
and Results of Operations and in Note 18, Segment
Information, in the notes to the financial statements.
|
United
|
Asia and
|
|||||||||||||||||||
| For the Years Ended December 31 | Total | States | Europe(a) | Africa | Other | |||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Sales and other operating revenues
|
||||||||||||||||||||
|
Unaffiliated customers
|
$ | 8,601 | $ | 2,310 | $ | 2,251 | $ | 2,750 | $ | 1,290 | ||||||||||
|
Inter-company
|
143 | 143 | — | — | — | |||||||||||||||
|
Total revenues
|
8,744 | 2,453 | 2,251 | 2,750 | 1,290 | |||||||||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Production expenses, including related taxes
|
1,924 | 489 | 727 | 455 | 253 | |||||||||||||||
|
Exploration expenses, including dry holes and lease impairment(b)
|
865 | 364 | 49 | 143 | 309 | |||||||||||||||
|
General, administrative and other expenses
|
281 | 161 | 48 | 20 | 52 | |||||||||||||||
|
Depreciation, depletion and amortization
|
2,222 | 649 | 463 | 772 | 338 | |||||||||||||||
|
Asset impairments
|
532 | — | — | 532 | — | |||||||||||||||
|
Total costs and expenses
|
5,824 | 1,663 | 1,287 | 1,922 | 952 | |||||||||||||||
|
Results of operations before income taxes
|
2,920 | 790 | 964 | 828 | 338 | |||||||||||||||
|
Provision for income taxes
|
1,583 | 305 | 477 | 580 | 221 | |||||||||||||||
|
Results of operations
|
$ | 1,337 | $ | 485 | $ | 487 | $ | 248 | $ | 117 | ||||||||||
89
Table of Contents
|
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(c)
|
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
|
2,113 | 503 | 419 | 821 | 370 | |||||||||||||||
|
Asset impairments
|
54 | — | 54 | — | — | |||||||||||||||
|
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(d)
|
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
|
1,922 | 225 | 574 | 888 | 235 | |||||||||||||||
|
Asset impairments
|
30 | 13 | 17 | — | — | |||||||||||||||
|
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 | ||||||||||
| (a) | In 2010, results of operations for oil and gas producing activities in Norway were as follows (millions of dollars): |
|
Sales and other operating revenues — Unaffiliated
customers
|
$ | 524 | ||
|
Costs and expenses
|
||||
|
Production expenses, including related taxes
|
149 | |||
|
Exploration expenses, including dry holes and lease
impairment
|
12 | |||
|
General, administrative and other expenses
|
9 | |||
|
Depreciation, depletion and amortization
|
133 | |||
|
Total costs and expenses
|
303 | |||
|
Results of operations before income taxes
|
221 | |||
|
Provision for income taxes
|
154 | |||
|
Results of operations
|
$ | 67 | ||
90
Table of Contents
| (b) | Includes $101 million ($64 million after income taxes) for dry hole expense in Egypt and Brazil. | |
| (c) | Includes $20 million ($15 million after income taxes) for reductions in carrying value of materials inventory in Equatorial Guinea. | |
| (d) | Includes $15 million ($9 million after income taxes) for Gulf of Mexico hurricane related costs. |
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 recognized 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. 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, which are discussed in Item 1A, Risk
Factors Related to Our Business and Operations on page 14
of this
Form 10-K.
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
and has over 30 years of experience in the oil and gas
industry with a BS degree in Petroleum Engineering. His
experience includes over 15 years primarily focused on oil
and gas subsurface understanding and reserves estimation in both
domestic and international areas. The Corporation’s
upstream technology organization, which Mr. Heck manages,
focuses on oil and gas industry subsurface and reservoir
engineering technologies and evaluation techniques.
Mr. Heck is also responsible for the Corporation’s
Global Reserves group, which is the internal organization
responsible for establishing the policies and processes used
within the operating units to estimate reserves and perform
internal technical reserve audits and reviews.
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 76% of
2010 year-end reported reserve quantities on a barrel of
oil equivalent basis (80% in 2009). The purpose of this audit
was to provide additional assurance on the reasonableness of
internally prepared reserve estimates and compliance with SEC
regulations. The D&M letter report, dated February 2,
2011, on the Corporation’s estimated oil and gas reserves
was prepared using standard geological and engineering methods
generally recognized in the petroleum industry. D&M is an
independent petroleum engineering consulting firm that has been
providing petroleum consulting services
91
Table of Contents
throughout the world for over 70 years. D&M’s
letter report on the Corporation’s December 31, 2010
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, differed by approximately
1% of total net proved reserves on a barrel of oil equivalent
basis. The report also includes among other information, the
qualifications of the technical person primarily responsible for
overseeing the reserve audit.
Adoption
of new SEC requirements in 2009
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. Effective with these changes, 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 2008, reserves were estimated
using year-end oil and gas prices.
Since it was not practical to calculate reserve estimates under
both the old and new reserve estimation standards as of year-end
2009, it was not possible to precisely measure the effect of
adopting the new SEC requirements on total proved reserves.
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.
92
Table of Contents
Following are the Corporation’s proved reserves for the
three years ended December 31, 2010:
|
Crude Oil, Condensate and Natural Gas
|
||||||||||||||||||||||||||||||||||||
| Liquids | Natural Gas | |||||||||||||||||||||||||||||||||||
|
Asia
|
||||||||||||||||||||||||||||||||||||
|
United
|
United
|
and
|
||||||||||||||||||||||||||||||||||
| States | Europe(g) | Africa | Asia | Total | States | Europe(g) | Africa(h) | Total | ||||||||||||||||||||||||||||
| (Millions of barrels) | (Millions of mcf) | |||||||||||||||||||||||||||||||||||
|
Net Proved Developed and Undeveloped Reserves
|
||||||||||||||||||||||||||||||||||||
|
At January 1, 2008
|
204 | 329 | 285 | 67 | 885 | 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 | 642 | 1,873 | 2,821 | ||||||||||||||||||||||||||
|
Revisions of previous estimates(b)
|
68 | 14 | 22 | (1 | ) | 103 | (7 | ) | (9 | ) | (23 | ) | (39 | ) | ||||||||||||||||||||||
|
Extensions, discoveries and other additions
|
3 | 19 | — | 1 | 23 | 14 | 15 | 1 | 30 | |||||||||||||||||||||||||||
|
Improved recovery
|
— | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||
|
Purchases of minerals in place
|
16 | 150 | — | — | 166 | 13 | 129 | — | 142 | |||||||||||||||||||||||||||
|
Sales of minerals in place
|
— | (13 | ) | (25 | ) | (5 | ) | (43 | ) | — | (4 | ) | (89 | ) | (93 | ) | ||||||||||||||||||||
|
Production
|
(32 | ) | (34 | ) | (41 | ) | (5 | ) | (112 | ) | (46 | ) | (54 | ) | (163 | ) | (263 | ) | ||||||||||||||||||
|
At December 31, 2010
|
304 | 466 | 270 | 64 | 1,104 | (c) | 280 | (d) | 719 | 1,599 | 2,598 | |||||||||||||||||||||||||
|
Net Proved Developed Reserves(e)
|
||||||||||||||||||||||||||||||||||||
|
At January 1, 2008
|
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 | |||||||||||||||||||||||||||
|
At December 31, 2010
|
180 | 210 | 215 | 22 | 627 | 199 | 424 | 692 | 1,315 | |||||||||||||||||||||||||||
|
Net Proved Undeveloped Reserves(f)
|
||||||||||||||||||||||||||||||||||||
|
At January 1, 2008
|
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 | |||||||||||||||||||||||||||
|
At December 31, 2010
|
124 | 256 | 55 | 42 | 477 | 81 | 295 | 907 | 1,283 | |||||||||||||||||||||||||||
| (a) | Proved reserves in 2008 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 2010, revisions included reductions of approximately 11 million barrels of crude oil and 62 million mcf of natural gas relating to higher selling prices. 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. | |
| (c) | Includes 15 million barrels in 2010, 17 million barrels in 2009 and 16 million barrels in 2008 of crude oil reserves relating to noncontrolling interest owners of corporate joint ventures. |
93
Table of Contents
| (d) | Excludes approximately 340 million mcf of carbon dioxide gas for sale or use in company operations. | |
| (e) | Of the total crude oil and natural gas liquids net proved developed reserves at December 31, 2010, 54 million barrels relate to natural gas liquids, 41 million barrels at December 31, 2009, 36 million barrels at December 31, 2008 and 33 million barrels at January 1, 2008. | |
| (f) | Of the total crude oil and natural gas liquids net proved undeveloped reserves at December 31, 2010, 48 million barrels relate to natural gas liquids, 30 million barrels at December 31, 2009, 22 million barrels at December 31, 2008 and 21 million barrels at January 1, 2008. | |
| (g) | In 2010, proved reserves in Norway were as follows: |
|
Crude Oil and
|
||||||||
| Natural Gas Liquids | Natural Gas | |||||||
| (Millions of barrels) | (Millions of mcf) | |||||||
|
At January 1, 2010
|
136 | 287 | ||||||
|
Revisions of previous estimates
|
(16 | ) | (1 | ) | ||||
|
Purchases of minerals in place
|
150 | 130 | ||||||
|
Production
|
(6 | ) | (12 | ) | ||||
|
At December 31, 2010
|
264 | 404 | ||||||
|
Net Proved Developed Reserves at December 31, 2010
|
97 | 157 | ||||||
|
Net Proved Undeveloped Reserves at December 31, 2010
|
167 | 247 | ||||||
| (h) | Natural gas reserves in Africa were 63 million mcf in 2010, 71 million mcf in 2009 and 69 million mcf in 2008. |
Proved
undeveloped reserves
The December 31, 2010 oil and gas reserve estimates
disclosed above include 477 million barrels of liquid
hydrocarbons and 1,283 million mcf of natural gas, or an
aggregate of 691 million barrels of oil equivalent (mmboe),
classified as proved undeveloped reserves. Overall volumes of
proved undeveloped reserves increased by 104 mmboe compared with
year-end 2009. Proved undeveloped reserves increased by 119
mmboe in 2010 from acquisitions in Norway and the Bakken oil
shale play in North Dakota. Approximately 30 mmboe of proved
undeveloped reserves in Indonesia, Gabon and the United Kingdom
were disposed of in asset sales and exchanges. Additions and
revisions in proved undeveloped reserves from existing fields
amounted to 73 mmboe, primarily in the United States, Denmark,
Libya and JDA. These increases resulted from ongoing technical
assessments, performance evaluations and development planning.
In 2010, 58 mmboe were converted from proved undeveloped
reserves to developed resulting from continuing development
activity and new wells in Libya, Russia, the Bakken in North
Dakota, the Llano Field in the Gulf of Mexico, the Pailin Field
in Thailand and the JDA. The Corporation estimates that capital
expenditures of approximately $600 million were incurred to
convert proved undeveloped reserves to developed during 2010.
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 175 mmboe or 11% of total 2010
proved reserves. Substantially all of the proved undeveloped
reserves in excess of five years old relate to five offshore
producing assets. Four natural gas projects in the JDA,
Indonesia and Norway are being developed in phases to satisfy
long-term natural gas sales contracts and an oil project in
Azerbaijan is continuing to be developed in phases. A summary of
the development status of each of the five projects follows:
| • | JDA — This natural gas project in the Gulf of Thailand currently has a central processing platform and six wellhead platforms. A seventh wellhead platform is under construction and the operator plans to begin construction of two additional wellhead platforms in 2011. | |
| • | Pangkah — This natural gas and oil project offshore Java, Indonesia currently has one producing offshore wellhead platform and onshore production facilities. A second wellhead platform has been installed and is currently supporting drilling operations. In addition, a central processing platform is currently under construction and is expected to be installed in 2011 to expand oil and water handling capacity. | |
| • | Natuna A — This natural gas project offshore Sumatra, Indonesia currently has one wellhead platform, a central processing facility and a floating, storage and offloading vessel. The operator is constructing a second wellhead platform and a separate central processing platform which is expected to be in service in 2011. Additional wellhead platforms and subsea well tie-backs are in the field development plan. |
94
Table of Contents
| • | Snohvit — This liquefied natural gas project offshore Norway currently has processing and liquefaction facilities on Melkoya Island with subsea wells tied-back to the facilities. Future development will continue based on available production capacity to meet contracted gas sales volumes. | |
| • | ACG — This oil project offshore Azerbaijan in the Caspian Sea has seven operational platforms that have been completed over multiple phases of development. The operator began construction on another production platform in 2010. |
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,
2010 are presented separately below, as well as volumes produced
and received during 2010, 2009 and 2008 from these production
sharing contracts.
| Crude Oil, Condensate and Natural Gas Liquids | Natural Gas | |||||||||||||||||||||||||||||||||||
|
Asia
|
||||||||||||||||||||||||||||||||||||
|
United
|
United
|
and
|
||||||||||||||||||||||||||||||||||
| States | Europe | Africa | Asia | Total | States | Europe | Africa | Total | ||||||||||||||||||||||||||||
| (Millions of barrels) | (Millions of mcf) | |||||||||||||||||||||||||||||||||||
|
Production Sharing Contracts
|
||||||||||||||||||||||||||||||||||||
|
Proved Reserves*
|
||||||||||||||||||||||||||||||||||||
|
At December 31, 2008
|
— | — | 188 | 82 | 270 | — | — | 1,604 | 1,604 | |||||||||||||||||||||||||||
|
At December 31, 2009
|
— | — | 161 | 68 | 229 | — | — | 1,599 | 1,599 | |||||||||||||||||||||||||||
|
At December 31, 2010
|
— | — | 108 | 57 | 165 | — | — | 1,316 | 1,316 | |||||||||||||||||||||||||||
|
Production
|
||||||||||||||||||||||||||||||||||||
|
2008
|
— | — | 37 | 4 | 41 | — | — | 103 | 103 | |||||||||||||||||||||||||||
|
2009
|
— | — | 36 | 5 | 41 | — | — | 136 | 136 | |||||||||||||||||||||||||||
|
2010
|
— | — | 33 | 4 | 37 | — | — | 130 | 130 | |||||||||||||||||||||||||||
| * | Includes natural gas liquids of 7 million barrels in 2010, 11 million barrels in 2009 and 12 million barrels in 2008. |
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 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.
95
Table of Contents
|
United
|
||||||||||||||||||||||
| At December 31 | Total | States | Europe* | Africa | Asia | |||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||
|
2010
|
||||||||||||||||||||||
|
Future revenues
|
$ | 91,336 | $ | 21,112 | $ | 36,157 | $ | 21,150 | $ | 12,917 | ||||||||||||
|
Less:
|
||||||||||||||||||||||
|
Future production costs
|
21,635 | 6,155 | 9,536 | 3,332 | 2,612 | |||||||||||||||||
|
Future development costs
|
13,554 | 3,178 | 6,534 | 1,269 | 2,573 | |||||||||||||||||
|
Future income tax expenses
|
30,250 | 4,423 | 11,745 | 12,173 | 1,909 | |||||||||||||||||
| 65,439 | 13,756 | 27,815 | 16,774 | 7,094 | ||||||||||||||||||
|
Future net cash flows
|
25,897 | 7,356 | 8,342 | 4,376 | 5,823 | |||||||||||||||||
|
Less: discount at 10% annual rate
|
10,195 | 3,764 | 3,361 | 1,028 | 2,042 | |||||||||||||||||
|
Standardized measure of discounted future net cash flows
|
$ | 15,702 | $ | 3,592 | $ | 4,981 | $ | 3,348 | $ | 3,781 | ||||||||||||
|
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 | ||||||||||||
96
Table of Contents
| * | In 2010, the standardized measure of discounted future net cash flows relating to proved reserves in Norway were as follows (millions of dollars): |
|
Future revenues
|
$ | 23,115 | ||
|
Less:
|
||||
|
Future production costs
|
4,399 | |||
|
Future development costs
|
3,426 | |||
|
Future income tax expenses
|
9,908 | |||
| 17,733 | ||||
|
Future net cash flows
|
5,382 | |||
|
Less: discount at 10% annual rate
|
2,156 | |||
|
Standardized measure of discounted future net cash flows
|
$ | 3,226 | ||
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
| For the Years Ended December 31 | 2010 | 2009 | 2008 | |||||||||||
| (Millions of dollars) | ||||||||||||||
|
Standardized measure of discounted future net cash flows at
beginning of year
|
$ | 11,401 | $ | 6,964 | $ | 21,905 | ||||||||
|
Changes during the year
|
||||||||||||||
|
Sales and transfers of oil and gas produced during the year, net
of production costs
|
(6,820 | ) | (5,030 | ) | (7,934 | ) | ||||||||
|
Development costs incurred during year
|
2,592 | 1,927 | 2,523 | |||||||||||
|
Net changes in prices and production costs applicable to future
production
|
7,970 | 7,484 | (28,627 | ) | ||||||||||
|
Net change in estimated future development costs
|
(1,678 | ) | (227 | ) | (1,056 | ) | ||||||||
|
Extensions and discoveries (including improved recovery) of oil
and gas reserves, less related costs
|
356 | 426 | 334 | |||||||||||
|
Revisions of previous oil and gas reserve estimates
|
1,885 | 1,855 | 1,730 | |||||||||||
|
Net purchases (sales) of minerals in place, before income taxes
|
3,193 | 165 | 18 | |||||||||||
|
Accretion of discount
|
2,011 | 1,235 | 4,109 | |||||||||||
|
Net change in income taxes
|
(5,848 | ) | (4,061 | ) | 13,859 | |||||||||
|
Revision in rate or timing of future production and other changes
|
640 | 663 | 103 | |||||||||||
|
Total
|
4,301 | 4,437 | (14,941 | ) | ||||||||||
|
Standardized measure of discounted future net cash flows at end
of year
|
$ | 15,702 | $ | 11,401 | $ | 6,964 | ||||||||
97
Table of Contents
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
QUARTERLY
FINANCIAL DATA
(Unaudited)
(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) | ||||||||||||||||
|
2010
|
||||||||||||||||
|
First
|
$ | 9,259 | $ | 1,395 | $ | 538 | (b) | $ | 1.65 | |||||||
|
Second
|
7,732 | 1,093 | 375 | 1.15 | ||||||||||||
|
Third
|
7,864 | 672 | 1,154 | (c) | 3.52 | |||||||||||
|
Fourth
|
9,007 | 1,288 | 58 | (d) | .18 | |||||||||||
|
2009
|
||||||||||||||||
|
First
|
$ | 6,915 | $ | 533 | $ | (59 | )(e) | $ | (.18 | ) | ||||||
|
Second
|
6,751 | 756 | 100 | (f) | .31 | |||||||||||
|
Third
|
7,270 | 832 | 341 | (g) | 1.05 | |||||||||||
|
Fourth
|
8,678 | 1,282 | 358 | (h) | 1.10 | |||||||||||
| (a) | Gross profit represents sales and other operating revenues, less cost of products sold, production expenses, marketing expenses, other operating expenses , depreciation, depletion and amortization and asset impairments. | |
| (b) | Includes an after-tax gain of $58 million related to an asset sale, partially offset by an after-tax charge of $7 million related to the repurchase of fixed-rate notes. | |
| (c) | Includes an after-tax gain of $1,072 million related to an asset exchange, partially offset by after-tax charges of $347 million related to an asset impairment. | |
| (d) | Includes an after-tax charge of $289 million relating to the Corporation’s impairment of its equity investment in HOVENSA and an after-tax charge of $51 million related to dry hole costs. | |
| (e) | 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. | |
| (f) | 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. | |
| (g) | Includes after-tax gains of $101 million primarily relating to the resolution of a royalty dispute. | |
| (h) | Includes after-tax charges of $34 million for the repurchase of fixed-rate notes and $10 million for pension plan settlements related to employee retirements. |
The results of operations for the periods reported herein should
not be considered as indicative of future operating results.
98
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, 2010, 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, 2010.
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, 2010 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.
PART III
| 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 4, 2011.
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 4, 2011.
99
Table of Contents
Executive
Officers of the Registrant
The following table presents information as of February 1,
2011 regarding executive officers of the Registrant:
|
Year Individual
|
||||||||||
|
Became an
|
||||||||||
|
Executive
|
||||||||||
| Name | Age | Office Held* | Officer | |||||||
|
John B. Hess
|
56 | Chairman of the Board, Chief Executive Officer and Director | 1983 | |||||||
|
Gregory P. Hill
|
49 | Executive Vice President and President of Worldwide Exploration and Production and Director | 2009 | |||||||
|
F. Borden Walker
|
57 | Executive Vice President and President of Marketing and Refining and Director | 1996 | |||||||
|
Timothy B. Goodell
|
53 | Senior Vice President and General Counsel | 2009 | |||||||
|
Lawrence H. Ornstein
|
59 | Senior Vice President | 1995 | |||||||
|
John P. Rielly
|
48 | Senior Vice President and Chief Financial Officer | 2002 | |||||||
|
John J. Scelfo
|
53 | Senior Vice President | 2004 | |||||||
|
Mykel J. Ziolo
|
58 | Senior Vice President | 2009 | |||||||
|
Robert M. Biglin
|
46 | Vice President and Treasurer | 2010 | |||||||
| * | 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 5, 2010, except for Mr. Biglin, who was elected effective September 1, 2010. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 4, 2011. |
Except for Messrs. Hill and Goodell, 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.
| 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 4, 2011.
| 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 4, 2011.
See Equity Compensation Plans in Item 5 for information
pertaining to securities authorized for issuance under equity
compensation plans.
| 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 4, 2011.
100
Table of Contents
| 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 4, 2011.
PART IV
| 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 3.1 of Form 8-K of Registrant filed on February 8, 2011. | |||
| 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 March 1, 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 of Registrant filed on December 15, 2009. |
101
Table of Contents
| 4(10) | Form of 5.60% Note incorporated by reference to Exhibit 4(1) to the Form 8-K of Registrant filed on August 12, 2010. 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 8, 2011. | ||
| 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) | * | First Amendment dated March 3, 2010 and approved May 5, 2010 to Registrant’s 2008 Long-Term Incentive Plan, incorporated by reference to Registrant’s definitive proxy statement dated March 25, 2010. | ||
| 10(15) | * | Forms of Awards under Registrant’s 2008 Long Term Incentive Plan incorporated by reference to Exhibit 10(14) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. | ||
| 10(16) | * | Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant filed on January 4, 2007. | ||
| 10(17) | * | 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. |
102
Table of Contents
| 10(18) | * | Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly incorporated by reference to Exhibit 10(17) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. 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(17)). | ||
| 10(19) | * | 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(20) | * | Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Item 5.02 of Form 8-K of Registrant filed January 7, 2009. | ||
| 10(21) | * | Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment incorporated by reference to Exhibit 10(20) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. | ||
| 10(22) | * | 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(23) | 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 filed on November 13, 1998. | |||
| 10(24) | 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 filed on November 13, 1998. | |||
| 21 | Subsidiaries of Registrant. | |||
| 23(1) | Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 25, 2011, to the incorporation by reference in Registrant’s Registration Statements (Form S-3 No. 333-157606, and Form S-8 Nos. 333-43569, 333-94851, 333-115844, 333-150992 and 333-167076), of its reports relating to Registrant’s financial statements. | |||
| 23(2) | Consent of DeGolyer and MacNaughton dated February 25, 2011. | |||
| 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 February 2, 2011, on proved reserves audit as of December 31, 2010 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. |
103
Table of Contents
| (b) | Reports on Form 8-K |
During the three months ended December 31, 2010, Registrant
filed or furnished the following reports on
Form 8-K:
1. Filing dated October 27, 2010 reporting under
Items 2.02 and 9.01, a news release dated October 27,
2010 reporting results for the third quarter of 2010.
2. Filing dated November 8, 2010 reporting under
Item 9.01, exhibits of opinions of White & Case
LLP as to the legality of notes registered on
Form S-3ASR
and incorporated by reference therein.
104
Table of Contents
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 25th day of
February 2011.
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 25, 2011 | ||||
|
/s/
Samuel
W. Bodman
|
Director | February 25, 2011 | ||||
|
/s/
Nicholas
F. Brady
|
Director | February 25, 2011 | ||||
|
/s/
Gregory
P. Hill
|
Director | February 25, 2011 | ||||
|
/s/
Edith
E. Holiday
|
Director | February 25, 2011 | ||||
|
/s/
Thomas
H. Kean
|
Director | February 25, 2011 | ||||
|
/s/
Risa
Lavizzo-Mourey
|
Director | February 25, 2011 | ||||
|
/s/
Craig
G. Matthews
|
Director | February 25, 2011 | ||||
|
/s/
John
H. Mullin
|
Director | February 25, 2011 | ||||
|
/s/
Frank
A. Olson
|
Director | February 25, 2011 | ||||
|
/s/
John
P. Rielly
|
Senior Vice President and Chief
Financial Officer (Principal Financial and Accounting Officer) |
February 25, 2011 | ||||
|
/s/
Ernst
H. von Metzsch
|
Director | February 25, 2011 | ||||
|
/s/
F.
Borden Walker
|
Director | February 25, 2011 | ||||
|
/s/
Robert
N. Wilson
|
Director | February 25, 2011 | ||||
105
Table of Contents
Schedule II
HESS
CORPORATION AND CONSOLIDATED SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2010, 2009 and 2008
VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2010, 2009 and 2008
| Additions | ||||||||||||||||||||||
|
Charged
|
||||||||||||||||||||||
|
to Costs
|
Charged
|
Deductions
|
||||||||||||||||||||
|
Balance
|
and
|
to Other
|
from
|
Balance
|
||||||||||||||||||
| Description | January 1 | Expenses | Accounts | Reserves | December 31 | |||||||||||||||||
| (In millions) | ||||||||||||||||||||||
|
2010
|
||||||||||||||||||||||
|
Losses on receivables
|
$ | 54 | $ | 9 | $ | 1 | $ | 6 | $ | 58 | ||||||||||||
|
2009
|
||||||||||||||||||||||
|
Losses on receivables
|
$ | 46 | $ | 13 | $ | — | $ | 5 | $ | 54 | ||||||||||||
|
2008
|
||||||||||||||||||||||
|
Losses on receivables
|
$ | 41 | $ | 9 | $ | — | $ | 4 | $ | 46 | ||||||||||||
106
Table of Contents
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 3.1 of Form 8-K of Registrant filed on February 8, 2011. | |||
| 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 March 1, 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 of Registrant filed on December 15, 2009. | |||
| 4(10) | Form of 5.60% Note incorporated by reference to Exhibit 4(1) to the Form 8-K of Registrant filed on August 12, 2010. 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. |
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| 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 8, 2011. | ||
| 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) | * | First Amendment dated March 3, 2010 and approved May 5, 2010 to Registrant’s 2008 Long-Term Incentive Plan, incorporated by reference to Registrant’s definitive proxy statement dated March 25, 2010. | ||
| 10(15) | * | Forms of Awards under Registrant’s 2008 Long Term Incentive Plan incorporated by reference to Exhibit 10(14) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. | ||
| 10(16) | * | Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant filed on January 4, 2007. | ||
| 10(17) | * | 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(18) | * | Change of Control Termination Benefits Agreement dated as of May 29, 2009 between Registrant and John P. Rielly incorporated by reference to Exhibit 10(17) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. 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(17)). | ||
| 10(19) | * | 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(20) | * | Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Item 5.02 of Form 8-K of Registrant filed January 7, 2009. | ||
| 10(21) | * | Agreement between Registrant and Timothy B. Goodell relating to his compensation and other terms of employment incorporated by reference to Exhibit 10(20) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009. | ||
| 10(22) | * | 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(23) | 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 filed on November 13, 1998. |
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| 10(24) | 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 filed on November 13, 1998. | |||
| 21 | Subsidiaries of Registrant. | |||
| 23(1) | Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 25, 2011, to the incorporation by reference in Registrant’s Registration Statements (Form S-3 No. 333-157606, and Form S-8 Nos. 333-43569, 333-94851, 333-115844, 333-150992 and 333-167076), of its reports relating to Registrant’s financial statements. | |||
| 23(2) | Consent of DeGolyer and MacNaughton dated February 25, 2011. | |||
| 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 February 2, 2011, on proved reserves audit as of December 31, 2010 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 IprintItem 1A. Risk Factors Related To Our Business and OperationsprintItem 3. Legal ProceedingsprintPart IIprintItem 5. Market For The Registrant S Common Stock, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesprintItem 6. Selected Financial DataprintItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 7A. Quantitative and Qualitative Disclosures About Market RiskprintItem 8. Financial Statements and Supplementary DataprintItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureprintItem 9A. Controls and ProceduresprintItem 9B. Other InformationprintPart IIIprintItem 10. Directors, Executive Officers and Corporate GovernanceprintItem 11. Executive CompensationprintItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersprintItem 13. Certain Relationships and Related Transactions, and Director IndependenceprintItem 14. Principal Accounting Fees and ServicesprintPart IVprintItem 15. Exhibits, Financial Statement Schedulesprint