<PAGE> 1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 Fee Required
For the fiscal year ended December 31, 1994
or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 No Fee Required
For the transition period from to
---------------- -------
COMMISSION FILE NUMBER 1-1204
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AMERADA HESS CORPORATION
(Exact name of Registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of incorporation or organization)
13-4921002
(I.R.S. Employer Identification Number)
1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y. 10036
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code, is (212) 997-8500)
------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
Common Stock (par value $1.00) New York Stock Exchange
Toronto Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark 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. /X/
The aggregate market value of voting stock held by non-affiliates of the
Registrant amounted to $3,892,000,000 as of February 28, 1995.
At February 28, 1995, 92,992,755 shares of Common Stock were outstanding.
Certain items in Parts I and II incorporate information by reference from
the 1994 Annual Report to Stockholders and Part III is incorporated by reference
from the Proxy Statement for the annual meeting of stockholders to be held on
May 3, 1995.
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<PAGE> 2
PART I
ITEM 1. BUSINESS
Amerada Hess Corporation (the "Registrant") was incorporated in 1920 in the
State of Delaware. The Registrant and its subsidiaries (collectively referred to
herein as the "Corporation") are engaged in the exploration for and the
production, purchase, gathering, transportation and sale of crude oil and
natural gas and the manufacture, purchase, transportation and marketing of
refined products.
EXPLORATION AND PRODUCTION
The Corporation's exploration and production activities are located
primarily in the United States, Canada, the United Kingdom and Norwegian sectors
of the North Sea and Gabon. The Corporation also conducts exploration and/or
production activities in Abu Dhabi, Denmark, Egypt, Namibia and Thailand. Of the
Company's proved reserves (on a barrel of oil equivalent basis), 34% are located
in the United States, 50% are located in the United Kingdom and Norwegian
sectors of the North Sea, 12% are located in Canada and the remainder are
located in Gabon and Abu Dhabi. Worldwide crude oil and natural gas liquids
production amounted to 250,520 barrels per day in 1994 compared with 215,390
barrels per day in 1993. Worldwide natural gas production was 846,118 Mcf per
day in 1994 compared with 887,309 Mcf per day in 1993.
At December 31, 1994, the Corporation has 644 million barrels of proved
crude oil and natural gas liquids reserves compared with 670 million barrels at
the end of 1993. Proved natural gas reserves are 2,581 million Mcf at December
31, 1994 compared with 2,653 million Mcf at December 31, 1993. The Corporation
has an inventory of drillable prospects primarily in the United States, Canada
and the United Kingdom and Norwegian sectors of the North Sea.
UNITED STATES. The Corporation operates principally offshore in the Gulf
of Mexico and onshore in the states of Texas, Louisiana and North Dakota. During
1994, 27% of the Corporation's crude oil and natural gas liquids production and
50% of its natural gas production were from United States operations.
The table below sets forth the Corporation's average daily net production
by area in the United States:
<TABLE>
<CAPTION>
1994 1993
------- -------
<S> <C> <C>
CRUDE OIL, INCLUDING CONDENSATE AND
NATURAL GAS LIQUIDS (BARRELS PER DAY)
Texas........................................................ 26,237 27,573
Gulf of Mexico............................................... 14,349 15,389
North Dakota................................................. 13,158 13,699
Alaska....................................................... 3,735 4,341
Louisiana.................................................... 2,331 2,546
Other........................................................ 7,792 8,423
------- -------
Total................................................ 67,602 71,971
======= =======
NATURAL GAS (MCF PER DAY)
Gulf of Mexico............................................... 217,203 283,340
Louisiana.................................................... 51,727 54,848
North Dakota................................................. 46,530 47,617
Texas........................................................ 39,973 47,508
New Mexico................................................... 23,276 21,942
California................................................... 19,623 19,744
Other........................................................ 28,771 27,460
------- -------
Total................................................ 427,103 502,459
======= =======
</TABLE>
CANADA. The Corporation, through its wholly-owned Canadian subsidiary,
Amerada Hess Canada Ltd., conducts operations in the Provinces of Alberta and
British Columbia. The Corporation's net crude oil and natural gas liquids
production in Canada amounted to 12,390 barrels per day in 1994 compared to
13,492 barrels per day in 1993, and its natural gas production increased to
185,856 Mcf per day in 1994 from 167,839 Mcf per day in 1993.
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UNITED KINGDOM. The Corporation's activities in the United Kingdom are
conducted by its wholly-owned British subsidiary, Amerada Hess Limited. During
1994, 51% of the Corporation's crude oil and natural gas liquids production and
25% of its natural gas production were from United Kingdom operations.
The table below sets forth the Corporation's average daily net production
in the United Kingdom by field and the Corporation's interest in each at
December 31, 1994:
<TABLE>
<CAPTION>
PRODUCING FIELD INTEREST 1994 1993
--------------- -------- ---- ----
<S> <C> <C> <C>
CRUDE OIL, INCLUDING CONDENSATE AND
NATURAL GAS LIQUIDS (BARRELS PER DAY)
Scott.................................. 34.95% 59,161 10,690
Ivanhoe/Rob Roy/Hamish................. 42.08 24,913 27,343
Beryl/Ness............................. 20.00 18,687 20,478
Arbroath/Montrose...................... 28.21 9,823 9,679
Hudson................................. 28.46 8,413 4,714
Other.................................. Various 7,802 10,898
------- -------
Total............................. 128,799 83,802
======= =======
NATURAL GAS (MCF PER DAY)
Beryl/Ness............................. 20.00% 43,329 46,219
Everest/Lomond......................... 18.67/16.67 41,685 18,596
Leman.................................. 21.74 28,663 48,523
Indefatigable.......................... 23.08 20,855 38,836
Scott.................................. 34.95 26,092 2,153
Anglia................................. 29.29 19,538 15,962
Other.................................. Various 28,580 17,735
------- -------
Total............................. 208,742 188,024
======= =======
</TABLE>
Crude oil production commenced from the Scott and Hudson Fields in the
third quarter of 1993. Natural gas production commenced from the Everest and
Lomond Fields in mid-1993.
NORWAY. The Corporation's activities in Norway are conducted through its
wholly-owned Norwegian subsidiary, Amerada Hess Norge A/S. The Corporation's
Norwegian operations accounted for crude oil and natural gas liquids production
of 25,599 and 27,820 net barrels per day in 1994 and 1993, respectively.
Approximately 60% of this production is from the Corporation's 28.09% interest
in the Valhall Field.
GABON. The Corporation has a 5.5% interest in the Rabi Kounga oil field
onshore Gabon. The Corporation's share of production from Gabon averaged 8,746
and 8,136 net barrels of crude oil per day in 1994 and 1993, respectively.
REFINING AND MARKETING
The Corporation's refining facilities are located in St. Croix, United
States Virgin Islands and Port Reading, New Jersey. The Purvis, Mississippi
refinery was mothballed in early 1994. Total crude runs averaged 388,000 barrels
per day in 1994 and 351,000 barrels per day in 1993. The Corporation's
production supplied approximately 15% of its crude runs. The balance came from
various suppliers under contracts of one year or less and through spot purchases
on the open market. Approximately 80% of the refined products marketed in 1994
was obtained from the Corporation's refineries. The Corporation purchased the
balance from other companies under short-term supply contracts and by spot
purchases from various sources. Sales of refined products averaged 468,000
barrels per day in 1994 compared with 386,000 barrels per day in 1993.
HESS OIL VIRGIN ISLANDS REFINERY. The Corporation owns and operates a
petroleum refinery in St. Croix, United States Virgin Islands through its
wholly-owned subsidiary, Hess Oil Virgin Islands Corp. ("HOVIC").
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<PAGE> 4
In 1994, refined products produced were approximately 65% gasoline and
distillates, 10% refinery feedstocks and the remainder principally residual fuel
oil. In addition to crude distillation capacity, the refinery has a fluid
catalytic cracking unit which commenced production in the fourth quarter of 1993
and increased gasoline production. The refinery also has catalytic reforming
units, vacuum distillation capacity, visbreakers, a sulfolane unit, a penex
unit, distillate desulfurizers, vacuum gas oil desulfurizers and sulfur recovery
facilities. The refinery has approximately 31 million barrels of storage
capacity.
The refinery has the capability to process a variety of crude oils,
including high-sulfur crudes. The refinery has a 60-foot-deep harbor and docking
facilities for ten ocean-going tankers at one time. The refinery's harbor
accommodates very large crude carriers after a portion of their crude oil cargo
is lightered at the Corporation's storage and transshipment facility in Saint
Lucia, which has a 90-foot-deep harbor. The Saint Lucia facility has
approximately 9 million barrels of storage capacity.
PORT READING FACILITY. The Corporation owns and operates a fluid catalytic
cracking facility in Port Reading, New Jersey, which processes vacuum gas oil
and operates at a rate of approximately 54,000 barrels per day. The Port Reading
facility primarily produces gasoline and heating oil.
MARKETING. The Corporation markets refined petroleum products principally
on the East and Gulf Coasts of the United States to the motoring public,
wholesale distributors, industrial and commercial users, other petroleum
companies, commercial airlines, governmental agencies and public utilities.
At December 31, 1994, the Corporation has 541 HESS(R) gasoline stations of
which approximately 82% are operated by the Corporation. Most of the
Corporation's stations are concentrated in highly-populated, urban areas,
principally in New York, New Jersey and Florida. Of the Corporation's stations,
155 have HESS MART(R) convenience stores. The Corporation owns in fee
approximately 75% of the properties on which its stations are located. The
Corporation also has 46 terminals located throughout its marketing area, with
aggregate storage capacity of approximately 49 million barrels.
COMPETITION AND MARKET CONDITIONS
The petroleum industry is highly competitive. The Corporation encounters
competition from numerous companies in each of its activities, particularly in
acquiring rights to explore for crude oil and natural gas and in the purchasing
and marketing of refined products. Many competitors are larger and have
substantially greater resources than the Corporation. The Corporation is also in
competition with producers and marketers of other forms of energy.
The petroleum business involves large-scale capital expenditures and
risk-taking. In the search for new oil and gas reserves, long lead times are
often required from successful exploration to subsequent production. Operations
in the petroleum industry depend on a depleting natural resource. The number of
areas where it can be expected that hydrocarbons will be discovered in
commercial quantities is constantly diminishing and exploration risks are high.
Areas where hydrocarbons may be found are often in remote locations or offshore
where exploration and development activities are capital intensive and operating
costs are high. In addition, low crude oil prices have reduced the number of
areas from which hydrocarbons can be economically produced.
The major foreign oil producing countries, including 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, oil prices, and
other matters has a significant impact on the oil market and the Corporation. In
recent years, the futures markets have become increasingly important in
influencing the prices of crude oil, natural gas and refined products. The
Corporation cannot predict the extent to which future market conditions may be
affected by OPEC, the futures markets or other external influences.
3
<PAGE> 5
Market conditions continue to affect the Corporation's earnings. The
Corporation's refining and marketing operations were profitable in 1994,
reflecting higher margins than in 1993, the operation of the fluid catalytic
cracking unit and increased refinery runs. However, the selling prices of all
refined products, particularly gasolines, continue to be subject to competitive
industry conditions. Supply and demand factors, including the effects of
weather, will continue to affect all refined product markets.
The Corporation's exploration and production operations were also
profitable in 1994, but continue to be impacted by volatility in the selling
prices of crude oil and natural gas. Average worldwide crude oil selling prices
declined in 1994, but improved somewhat late in the year. In 1994, the available
supply of natural gas in the United States exceeded demand, resulting in sharply
lower selling prices. The lower natural gas selling prices continued into 1995
and the Corporation is unable to predict how long these conditions will exist.
OTHER ITEMS
The Corporation's operations may be affected by federal, state, local,
territorial and foreign laws and regulations relating to tax increases and
retroactive tax claims, expropriation of property, cancellation of contract
rights, and changes in import regulations, as well as other political
developments. The Corporation has been affected by certain of these events in
various countries in which it operates. The Corporation markets 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 is periodically proposed in
Congress and in various other states. The Corporation, at this time, cannot
predict the effect of any of the foregoing on its future operations.
Compliance with the various environmental and pollution control regulations
imposed by federal, state and local governments is not expected to have a
materially adverse effect on the Corporation's earnings and competitive position
within the industry. However, the cost of such compliance is expected to
increase in the future. Capital expenditures for facilities, primarily to comply
with federal, state and local environmental standards, were $8 million in 1994
and the Corporation anticipates comparable capital expenditures in 1995. In
addition, the Corporation expended $16 million in 1994 for environmental
remediation, with a comparable amount anticipated for 1995.
The number of persons employed by the Corporation averaged 9,858 in 1994
and 10,173 in 1993.
Additional operating and financial information relating to the business and
properties of the Corporation appears on pages 6 and 9 under the heading "United
States Exploration and Production," on pages 10, 13 and 14 under the heading
"International Exploration and Production," on pages 17 and 18 under the heading
"Refining and Marketing," on pages 21 through 25 under the heading "Financial
Review" and on pages 26 through 51 of the accompanying 1994 Annual Report to
Stockholders, which information is incorporated herein by reference.*
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* Except as to information specifically incorporated herein by reference under
Items 1, 2, 5, 6, 7 and 8, no other information or data appearing in the 1994
Annual Report to Stockholders is deemed to be filed with the Securities and
Exchange Commission (SEC) as part of this Annual Report on Form 10-K, or
otherwise subject to the SEC's regulations or the liabilities of Section 18 of
the Securities Exchange Act of 1934, as amended.
4
<PAGE> 6
ITEM 2. PROPERTIES
Reference is made to Item 1 and the operating and financial information
relating to the business and properties of the Corporation, which is
incorporated in Item 1 by reference.
Additional information relating to the Corporation's oil and gas operations
follows.
1. OIL AND GAS RESERVES
The Corporation's net proved oil and gas reserves at the end of 1994, 1993
and 1992 are presented under Supplementary Oil and Gas Data in the accompanying
1994 Annual Report to Stockholders, which has been incorporated herein by
reference.
During 1994, the Corporation provided oil and gas reserve estimates for
1993 to the Department of Energy. Such estimates are compatible with the
information furnished to the SEC on Form 10-K, although not necessarily directly
comparable due to the requirements of the individual requests. There were no
differences in excess of 5%.
The Corporation has no long-term contracts or agreements to supply fixed
quantities of its crude oil production. Approximately 60% of the Corporation's
1994 natural gas sales were made under long-term contracts to various
purchasers. Contractual commitments in 1995 (which are expected to be comparable
to 1994) will be filled from the Corporation's production and from contractual
purchases.
2. AVERAGE SELLING PRICES AND AVERAGE PRODUCTION COSTS
<TABLE>
<CAPTION>
1994 1993 1992
-----------------------------------------------------------------------------------
<S> <C> <C> <C>
Average selling prices (Note A)
Crude oil, including condensate and natural
gas liquids (per barrel)
United States.......................... $ 15.43 $ 17.40 $ 17.94
Canada................................. 15.94 16.30 17.05
Europe................................. 15.96 17.04 19.79
Other areas............................ 15.45 16.41 18.70
Average................................ 15.78 17.05 18.92
Natural gas (per Mcf)
United States.......................... $ 1.91 $ 2.11 $ 1.76
Canada................................. 1.36 1.43 1.24
Europe................................. 2.04 1.83 1.83
Average................................ 1.86 1.98 1.72
----------------------------------------------------------------------------------
</TABLE>
Note A: Includes inter-company transfers valued at approximate market
prices and the effect of the Corporation's hedging activities.
5
<PAGE> 7
<TABLE>
<CAPTION>
1994 1993 1992
---------------------------------------------------------------------------------
<S> <C> <C> <C>
Average production (lifting) costs per barrel of
production (Note B)
United States.......................... $ 4.10 $ 4.06 $ 3.43
Canada................................. 2.98 3.21 3.61
Europe................................. 4.37 4.89 6.03
Other areas............................ 3.08 4.15 4.01
Average................................ 4.06 4.31 4.51
</TABLE>
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Note B: Production (lifting) costs consist of amounts incurred to operate
and maintain the Corporation's producing oil and gas wells and related equipment
and facilities, including severance and other related production taxes. The
average production (lifting) costs per barrel of production reflect the crude
oil equivalent of natural gas production converted on the basis of relative
energy content.
The foregoing tabulation does not include substantial costs and charges
applicable to finding and developing proved oil and gas reserves, nor does it
reflect significant outlays for related general and administrative expenses,
interest expense and income taxes.
3. GROSS AND NET DEVELOPED ACREAGE AND PRODUCTIVE WELLS AT DECEMBER 31, 1994
<TABLE>
<CAPTION>
DEVELOPED
ACREAGE PRODUCTIVE WELLS (NOTE A)
APPLICABLE TO -------------------------------------
PRODUCTIVE WELLS
(IN THOUSANDS) OIL GAS
----------------- ----------------
------------------------------------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
United States...................... 3,011 686 15,100 1,630 2,003 780
Canada............................. 789 392 1,927 473 1,024 339
Europe............................. 491 91 379 40 133 27
Other areas........................ 91 25 131 17 - -
------ ------ ------- ------ ------ ------
Total.................... 4,382 1,194 17,537 2,160 3,160 1,146
===== ===== ====== ===== ===== =====
</TABLE>
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Note A: Includes multiple completion wells (wells producing from different
formations in the same bore hole) totaling 240 gross wells and 123 net wells.
4. GROSS AND NET UNDEVELOPED ACREAGE AT DECEMBER 31, 1994
<TABLE>
<CAPTION>
UNDEVELOPED
ACREAGE
(IN THOUSANDS)
-----------------
GROSS NET
------------------------------------------------------------------
<S> <C> <C>
United States................................ 2,467 1,685
Canada....................................... 1,332 743
Europe....................................... 7,188 2,163
Other areas.................................. 6,694 1,664
------- ------
Total.............................. 17,681 6,255
====== =====
</TABLE>
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5. NUMBER OF NET EXPLORATORY AND DEVELOPMENT WELLS DRILLED
<TABLE>
<CAPTION>
NET EXPLORATORY WELLS NET DEVELOPMENT WELLS
---------------------- ----------------------
1994 1993 1992 1994 1993 1992
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Productive wells
United States................. 10 25 12 27 43 25
Canada........................ 9 9 1 13 10 7
Europe........................ 5 6 Nil 6 3 7
Other areas................... 1 Nil - 1 1 1
---- ---- ---- ---- ---- ----
Total.................... 25 40 13 47 57 40
---- ---- ---- ---- ---- ----
Dry holes
United States................. 17 23 16 - 1 -
Canada........................ 5 10 5 1 2 Nil
Europe........................ 1 1 1 - - -
Other areas................... Nil - Nil - - -
---- ---- ---- ---- ---- ----
Total.................... 23 34 22 1 3 Nil
---- ---- ---- ---- ---- ----
Total.............................. 48 74 35 48 60 40
==== ==== ==== ==== ==== ====
</TABLE>
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6. NUMBER OF WELLS IN PROCESS OF DRILLING AT DECEMBER 31, 1994
<TABLE>
<CAPTION>
GROSS NET
WELLS WELLS
--------------------------------------------------------------------------------
<S> <C> <C>
United States.................................... 41 17
Canada........................................... 11 4
Europe........................................... 11 3
Other areas...................................... 2 Nil
----- -----
Total.................................. 65 24
==== ====
</TABLE>
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7. NUMBER OF WATERFLOODS AND PRESSURE MAINTENANCE PROJECTS IN PROCESS OF
INSTALLATION AT DECEMBER 31, 1994 -- None
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ITEM 3. LEGAL PROCEEDINGS
The Registrant is currently the subject of an investigation by United
States Attorneys for the federal judicial district in New Jersey and the United
States Environmental Protection Agency ("EPA") with respect to possible
violations of federal environmental and other laws and regulations in connection
with hazardous waste handling at the HOVIC refinery. That investigation
apparently focuses on whether or not certain spent catalyst generated at the
HOVIC refinery should have been managed as a hazardous waste under the Resource
Conservation and Recovery Act ("RCRA"), and, if it should have been managed as a
hazardous waste, whether or not such catalyst was stored beyond the time period
permitted under RCRA, whether or not Registrant and/or HOVIC failed to comply
with certain environmental reporting requirements related thereto and whether or
not any false statements were made to the United States government by employees
of the Registrant or HOVIC in connection therewith. The Registrant is also the
subject of an investigation by United States Attorneys for the federal judicial
district in Arizona arising out of the shipment of such catalyst to a third
party in Arizona. This investigation apparently focuses on whether or not
Registrant or HOVIC participated in a failure to comply in a timely manner with
certain reporting obligations in connection with the use and receipt of such
catalyst by such third party under the Comprehensive Environmental Response,
Compensation, and Liability Act, and whether or not employees of the Registrant
or HOVIC made any false statements to the United States government in connection
therewith. It is not possible at this time for Registrant to state what the
outcome of these investigations will be, or, if any proceedings arising out of
the
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investigations were to be commenced against the Registrant or HOVIC, what claims
would be asserted or what relief would be sought.
On April 27, 1993, the Texas Natural Resource Conservation Commission
("TNRCC", then known as the Texas Water Commission) notified the Registrant of
alleged violation of the Texas Water Code as a result of alleged discharges of
hydrocarbon compounds into the groundwater in the vicinity of the Registrant's
terminal in Corpus Christi, Texas. Penalties provided for these violations
include administrative penalties not to exceed $10,000 per day. The Registrant
has undertaken a groundwater assessment, an interim correction measures program
and other appropriate responses to these allegations. On December 9, 1994, the
Executive Director of the TNRCC forwarded a Notice of Executive Director's
Preliminary Report and Petition for a TNRCC Order Assessing Administrative
Penalties and Requiring Certain Actions of Amerada Hess Corporation. This Notice
recommended a $542,400 penalty be assessed and the Registrant be ordered to
undertake remedial actions at the Corpus Christi terminal. The Registrant has
begun settlement discussions with the TNRCC regarding this matter.
On June 21, 1994, Region II of the EPA commenced an administrative
proceeding under Section 325 of the Emergency Planning and Community
Right-to-Know Act ("EPCRA") against HOVIC, alleging violations of Section 313 of
EPCRA arising out of HOVIC's alleged failure to comply with certain reporting
requirements relating to toxic chemicals manufactured or otherwise used at
HOVIC's refinery. The proceeding seeks civil penalties totaling $252,000 for the
alleged violations. HOVIC is engaging in settlement discussions with the EPA
regarding this matter.
The Corporation periodically receives notices from the EPA that the
Corporation is a "potentially 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 which are not material. The ultimate
impact of these proceedings, and of any related proceedings by private parties,
on the business or accounts of the Corporation cannot be predicted at this time
due to the large number of other potentially responsible parties and the
speculative nature of clean-up cost estimates, but is not expected to be
material.
The Corporation is from time to time involved in other judicial and
administrative proceedings, including proceedings relating to other
environmental matters. Although the ultimate outcome of these proceedings cannot
be ascertained at this time and some of them may be resolved adversely to the
Corporation, no such proceeding is required to be disclosed under applicable
rules of the Securities and Exchange Commission. In management's opinion, based
upon currently known facts and circumstances, such proceedings in the aggregate
will not have a material adverse effect on the financial condition of the
Corporation.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1994, no matter was submitted to a vote of
security holders through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table presents information as of February 1, 1995 regarding
executive officers of the Registrant:
<TABLE>
<CAPTION>
YEAR
INDIVIDUAL
BECAME AN
EXECUTIVE
NAME AGE OFFICE HELD* OFFICER
--------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Leon Hess............... 80 Chairman of the Board, Chief Executive 1969
Officer and Director
Robert F. Wright........ 69 President, Chief Operating Officer and 1971
Director
John B. Hess............ 40 Senior Executive Vice President and Director 1983
H. W. McCollum.......... 81 Chairman of the Finance Committee and 1969
Director
J. Barclay Collins II... 50 Executive Vice President, General Counsel and 1986
Director
W. S. H. Laidlaw........ 39 Executive Vice President and Director 1986
Michael W. Press........ 47 Executive Vice President and Director 1994
John Y. Schreyer........ 55 Executive Vice President, Chief Financial 1990
Officer and Director
Alan A. Bernstein....... 50 Senior Vice President 1987
Marco B. Bianchi........ 55 Senior Vice President and Director 1986
James F. Cassidy........ 67 Senior Vice President 1992
F. Lamar Clark.......... 61 Senior Vice President 1990
Neal Gelfand............ 50 Senior Vice President 1980
Charles H. Norz......... 57 Senior Vice President 1982
Benedict J. O'Bryan..... 57 Senior Vice President 1991
Rene L. Sagebien........ 54 Senior Vice President 1990
Gerald A. Jamin......... 53 Treasurer 1985
</TABLE>
--------------------------------------------------------------------------------
* All officers referred to herein hold office in accordance with the
By-Laws until the first meeting of the Directors following the annual meeting of
stockholders of the Registrant, and until their successors shall have been duly
chosen and qualified. Each of said officers was elected to the office set forth
opposite his name on May 4, 1994, except that Mr. Press was elected to his
present office by the Board of Directors at its regular meeting on October 5,
1994. The first meeting of Directors following the next annual meeting of
stockholders of the Registrant is scheduled to be held May 3, 1995.
Except for Messrs. Schreyer and Press, each of the above officers has been
employed by the Registrant in various managerial and executive capacities for
more than five years. Prior to his employment with the Registrant in July 1990,
Mr. Schreyer was a partner with the accounting firm of Ernst & Young LLP. Prior
to his employment with the Registrant in October 1994, Mr. Press was a Senior
Vice President of BP Oil Company, a unit of The British Petroleum Company p.l.c.
9
<PAGE> 11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
Information pertaining to the market for the Registrant's Common Stock,
high and low sales prices of the Common Stock in 1994 and 1993, dividend
payments and restrictions thereon and the number of holders of Common Stock is
presented on page 25 (Financial Review), page 33 (Long-Term Debt) and on page 48
(Ten-Year Summary of Financial Data) of the accompanying 1994 Annual Report to
Stockholders, which has been incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
A Ten-Year Summary of Financial Data is presented on pages 46 through 49 of
the accompanying 1994 Annual Report to Stockholders, which has been incorporated
herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required by this item is presented on pages 21 through 25
of the accompanying 1994 Annual Report to Stockholders, which has been
incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements, including the Report of Ernst &
Young LLP, Independent Auditors, the Supplementary Oil and Gas Data (unaudited)
and the Quarterly Financial Data (unaudited) are presented on pages 25 through
45 of the accompanying 1994 Annual Report to Stockholders, which has been
incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
------------------------
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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 3, 1995.
Information regarding executive officers is included in Part I hereof.
ITEM 11. EXECUTIVE COMPENSATION
Information relating to executive compensation is incorporated herein by
reference to "Election of Directors-Executive Compensation and Other
Information," other than information under "Compensation Committee Report on
Executive Compensation" and "Performance Graph" included therein, from the
Registrant's definitive proxy statement for the annual meeting of stockholders
to be held on May 3, 1995.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
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 3, 1995.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 3, 1995.
------------------------
10
<PAGE> 12
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(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.
3. EXHIBITS
<TABLE>
<S> <C>
3(1) -Restated Certificate of Incorporation of Registrant incorporated by
reference to Exhibit 19 of Form 10-Q of Registrant for the three
months ended September 30, 1988.
3(2) -By-Laws of Registrant incorporated by reference to Exhibit 3(2) of
Form 10-K of Registrant for the fiscal year ended December 31,
1985.
4(1) -Note and Warrant Purchase Agreement, dated June 27, 1991 (including
the form of the Common Stock Purchase Warrant expiring June 27,
2001, included as Exhibit B thereof) incorporated by reference to
Exhibit 4 of Form 10-Q of Registrant for the three months ended
June 30, 1991.
4(2) -Amendment, dated as of May 15, 1992 to the Note and Warrant
Purchase Agreement, dated June 27, 1991 (including the form of the
common stock purchase warrant expiring June 27, 2001, included as
Exhibit B thereof), incorporated by reference to Exhibit 19 of
Form 10-Q of Registrant for the three months ended June 30, 1992.
-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)* -Incentive Compensation Award Plan for Key Employees of Amerada Hess
Corporation and its subsidiaries incorporated by reference to
Exhibit 10(2) of Form 10-K of Registrant for the fiscal year ended
December 31, 1980.
10(5)* -Financial Counseling Program description incorporated by reference
to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year
ended December 31, 1980.
</TABLE>
11
<PAGE> 13
3. EXHIBITS (continued)
<TABLE>
<S> <C>
10(6)* -Executive Long-Term Incentive Compensation and Stock Ownership Plan
of Registrant dated June 3, 1981 incorporated by reference to
Exhibit 10(5) of Form 10-Q of Registrant for the three months
ended June 30, 1981.
10(7)* -Amendment dated as of December 5, 1990 to the Executive Long-Term
Incentive Compensation and Stock Ownership Plan of Registrant
incorporated by reference to Exhibit 10(9) of Form 10-K of
Registrant for the fiscal year ended December 31, 1990.
10(8)* -Amerada 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(9)* -Letter Agreement dated August 8, 1990 between Registrant and Mr.
John Y. Schreyer relating to Mr. Schreyer's participation in the
Amerada Hess Corporation Pension Restoration Plan incorporated by
reference to Exhibit 10(11) of Form 10-K of Registrant for the
fiscal year ended December 31, 1991.
10(10)* -Letter Agreement dated November 2, 1994 between Registrant and Mr.
Michael W. Press relating to Mr. Press's participation in the
Amerada Hess Corporation Pension Restoration Plan and his
severance benefits.
13 -1994 Annual Report to Stockholders of Registrant.
21 -Subsidiaries of Registrant.
23 -Consent of Ernst & Young LLP, Independent Auditors, dated March 24,
1995, to the incorporation by reference in Registrant's
Registration Statement on Form S-8 (No. 33-39816) of its report
relating to Registrant's financial statements, which consent
appears on page F-2 herein.
27 -Financial Data Schedule (for electronic filing only).
</TABLE>
--------------------------------------------------------------------------------
* These exhibits relate to executive compensation plans and arrangements.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the last quarter of Registrant's
fiscal year ended December 31, 1994.
12
<PAGE> 14
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 24TH DAY OF
MARCH 1995.
AMERADA HESS CORPORATION
(REGISTRANT)
By /s/ JOHN Y. SCHREYER
..............................
(JOHN Y. SCHREYER)
EXECUTIVE 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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
----------------------------------------------------------------------------------------------
<S> <C> <C>
Director, Chairman of
the Board and
Chief Executive Officer
/s/ LEON HESS (Principal Executive Officer) March 24, 1995
.............................................
(LEON HESS)
Director, President and Chief
/s/ ROBERT F. WRIGHT Operating Officer March 24, 1995
.............................................
(ROBERT F. WRIGHT)
/s/ MARCO B. BIANCHI Director March 24, 1995
.............................................
(MARCO B. BIANCHI)
/s/ NICHOLAS F. BRADY Director March 24, 1995
.............................................
(NICHOLAS F. BRADY)
/s/ J. BARCLAY COLLINS II Director March 24, 1995
.............................................
(J. BARCLAY COLLINS II)
/s/ BERNARD T. DEVERIN Director March 24, 1995
.............................................
(BERNARD T. DEVERIN)
/s/ PETER S. HADLEY Director March 24, 1995
.............................................
(PETER S. HADLEY)
/s/ JOHN B. HESS Director March 24, 1995
.............................................
(JOHN B. HESS)
/s/ EDITH E. HOLIDAY Director March 24, 1995
.............................................
(EDITH E. HOLIDAY)
/s/ THOMAS H. KEAN Director March 24, 1995
.............................................
(THOMAS H. KEAN)
/s/ W. S. H. LAIDLAW Director March 24, 1995
.............................................
(W. S. H. LAIDLAW)
/s/ H. W. MCCOLLUM Director March 24, 1995
.............................................
(H. W. MCCOLLUM)
</TABLE>
13
<PAGE> 15
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
----------------------------------------------------------------------------------------------
<S> <C> <C>
/s/ ROGER B. ORESMAN Director March 24, 1995
.........................................
(ROGER B. ORESMAN)
/s/ WILLIAM A. POGUE Director March 24, 1995
.........................................
(WILLIAM A. POGUE)
/s/ MICHAEL W. PRESS Director March 24, 1995
.........................................
(MICHAEL W. PRESS)
Director, Executive Vice
President
and Chief Financial Officer
(Principal Accounting and
/s/ JOHN Y. SCHREYER Financial Officer) March 24, 1995
.........................................
(JOHN Y. SCHREYER)
/s/ RICHARD B. SELLARS Director March 24, 1995
.........................................
(RICHARD B. SELLARS)
Director March 24, 1995
.........................................
(WILLIAM I. SPENCER)
----------------------------------------------------------------------------------------------
</TABLE>
14
<PAGE> 16
AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
<TABLE>
<CAPTION>
PAGE
NUMBER
------------------------------------------------------------------------------------------
<S> <C>
Consolidated Balance Sheet at December 31, 1994 and 1993......................... *
Statement of Consolidated Income for each of the three years in the period ended
December 31, 1994.............................................................. *
Statement of Consolidated Retained Earnings for each of the three years in the
period ended December 31, 1994................................................. *
Statement of Consolidated Cash Flows for each of the three years in the period
ended December 31, 1994........................................................ *
Statement of Consolidated Changes in Common Stock and Capital in Excess of Par
Value for each of the three years in the period ended December 31, 1994........ *
Notes to Consolidated Financial Statements....................................... *
Report of Ernst & Young LLP, Independent Auditors................................ *
Quarterly Financial Data......................................................... *
Supplementary Oil and Gas Data................................................... *
Consent of Independent Auditors.................................................. F-2
Schedules........................................................................ **
----------------------------------------------------------------------------------------
</TABLE>
* The financial statements and notes thereto together with the Report of
Ernst & Young LLP, Independent Auditors, on pages 26 through 40, the Quarterly
Financial Data (unaudited) on page 25, and the Supplementary Oil and Gas Data
(unaudited) on pages 41 through 45 of the accompanying 1994 Annual Report to
Stockholders are incorporated herein by reference.
** All schedules 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.
F-1
<PAGE> 17
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in this Annual Report (Form
10-K) of Amerada Hess Corporation of our report dated February 15, 1995,
included in the 1994 Annual Report to Stockholders of Amerada Hess Corporation.
We also consent to the incorporation by reference in the Registration
Statement (Form S-8, No. 33-39816) pertaining to the Amerada Hess Corporation
Employees' Savings and Stock Bonus Plan, of our report dated February 15, 1995,
with respect to the consolidated financial statements incorporated herein by
reference.
/S/ ERNST & YOUNG LLP
ERNST & YOUNG LLP
New York, N.Y.
March 24, 1995
F-2
<PAGE> 18
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
---------- ------------------------------------------------------------
<S> <C>
3(1) -- Restated Certificate of Incorporation of Registrant
incorporated by reference to Exhibit 19 of Form 10-Q of
Registrant for the three months ended September 30, 1988.
3(2) -- By-Laws of Registrant incorporated by reference to Exhibit
3(2) of Form 10-K of Registrant for the fiscal year ended
December 31, 1985.
4(1) -- Note and Warrant Purchase Agreement, dated June 27, 1991
(including the form of the Common Stock Purchase Warrant
expiring June 27, 2001, included as Exhibit B thereof)
incorporated by reference to Exhibit 4 of Form 10-Q of
Registrant for the three months ended June 30, 1991.
4(2) -- Amendment, dated as of May 15, 1992 to the Note and Warrant
Purchase Agreement, dated June 27, 1991 (including the form
of the common stock purchase warrant expiring June 27, 2001,
included as Exhibit B thereof), incorporated by reference to
Exhibit 19 of Form 10-Q of Registrant for the three months
ended June 30, 1992.
-- 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)* -- Incentive Compensation Award Plan for Key Employees of
Amerada Hess Corporation and its subsidiaries incorporated
by reference to Exhibit 10(2) of Form 10-K of Registrant for
the fiscal year ended December 31, 1980.
10(5)* -- Financial Counseling Program description incorporated by
reference to Exhibit 10(3) of Form 10-K of Registrant for
the fiscal year ended December 31, 1980.
10(6)* -- Executive Long-Term Incentive Compensation and Stock
Ownership Plan of Registrant dated June 3, 1981 incorporated
by reference to Exhibit 10(5) of Form 10-Q of Registrant for
the three months ended June 30, 1981.
10(7)* -- Amendment dated as of December 5, 1990 to the Executive
Long-Term Incentive Compensation and Stock Ownership Plan of
Registrant incorporated by reference to Exhibit 10(9) of
Form 10-K of Registrant for the fiscal year ended December
31, 1990.
10(8)* -- Amerada 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.
</TABLE>
<PAGE> 19
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
---------- ------------------------------------------------------------
<S> <C>
10(9)* -- Letter Agreement dated August 8, 1990 between Registrant and
Mr. John Y. Schreyer relating to Mr. Schreyer's
participation in the Amerada Hess Corporation Pension
Restoration Plan incorporated by reference to Exhibit 10(11)
of Form 10-K of Registrant for the fiscal year ended
December 31, 1991.
10(10)*-- Letter Agreement dated November 2, 1994 between Registrant
and Mr. Michael W. Press relating to Mr. Press's
participation in the Amerada Hess Corporation Pension
Restoration Plan and his severance benefits.
13 -- 1994 Annual Report to Stockholders of Registrant.
21 -- Subsidiaries of Registrant.
23 -- Consent of Ernst & Young LLP, Independent Auditors, dated
March 24, 1995, to the incorporation by reference in
Registrant's Registration Statement on Form S-8 (No.
33-39816) of its report relating to Registrant's financial
statements, which consent appears on page F-2 herein.
27 -- Financial Data Schedule (for electronic filing only).
</TABLE>
--------------------------------------------------------------------------------
* These exhibits relate to executive compensation plans and arrangements.
<PAGE> 1
EXHIBIT 10(10)
AMERADA HESS CORPORATION
LEON HESS 1185 AVENUE OF THE AMERICAS
Chairman of the Board NEW YORK, NEW YORK 10036-2677
(212) 997-8400
November 2, 1994
Mr. Michael W. Press
10 Alder Creek Drive
Califon, NJ 07830
Dear Mr. Press:
This letter will confirm our understanding concerning your participation in the
Amerada Hess Corporation Pension Restoration Plan (the "PRP") and the deferred
compensation you will receive in connection with your employment by Amerada Hess
Corporation (the "Corporation") on October 1, 1994, and other matters.
You have advised us that you have received or will receive lump sum payments
representing your accrued pension benefits under the qualified and non-qualified
pension plans of your previous employer, BP Oil Company ("BP"), and as a result,
you will not be entitled to pension payments from BP when you eventually retire.
Of the total amount, we understand that one portion is an eligible rollover
distribution that can be rolled over to an eligible retirement plan on a
tax-deferred basis (the "Non-taxable BP Distribution"), and the other portion is
taxable in the current year as ordinary income (the "Taxable BP Distribution").
We have estimated your incremental combined tax rate for 1994 as 48.28%
(federal, state and local income tax, and Medicare portion of FICA), and as a
result, the net available amount of your Taxable BP Distribution will be reduced
by 48.28%, resulting in a lesser amount available to you for investment (the
"Tax-adjusted BP Distribution").
The Board of Director's Compensation and Incentive Awards Committee has
determined that you will receive Prior Service (as defined in Section 4.1 of the
PRP) for 24 years of related experience acquired prior to the date of your
employment by the Corporation for the purpose of determining PRP benefits
calculated subject to the conditions set forth below.
1. Within 90 days following the sale of the property you own in
Cleveland you will invest the Tax-adjusted BP Distribution (plus 3% interest
per year from October 1, 1994 to the date of investment) with an insurance
company in a single premium annuity contract that will provide an annual
life annuity benefit to you upon retirement. The carrier and contract are
to be reviewed and approved in advance by the Corporation, and such approval
shall not be withheld unreasonably. Such contract will be held by you until
retirement and shall not be subject to loans, anticipation or alienation
prior to the date of your retirement.
2. Within 60 days of the distribution by BP of the Non-taxable BP
Distribution, you will invest it in an individual retirement account ("IRA")
in your name, and
<PAGE> 2
Mr. Michael W. Press November 2, 1994
provide written acknowledgement of the receipt of such amount by the IRA
trustee. You will continue to hold the full principal amount plus earnings
in the IRA and will not withdraw the funds from the IRA until your
retirement.
3. Annual benefits payable to you pursuant to the Corporation's PRP upon
your retirement under the Pension Plan will be determined by deducting from
the life annuity amount calculated under the PRP the sum of A, B and C
below.
A. The annual benefit actually payable to you as a life annuity
under the Corporation's Employees' Pension Plan (the "Pension Plan")
based on your Credited Service, determined without regard to the
Prior Service granted under the PRP.
B. A life annuity that would be payable commencing at your
retirement under the terms of the annuity contract described in
paragraph 1 above, grossed up to reflect the fact that no income
taxes will be payable on the portion of the annuity derived from your
initial after-tax investment. If the Cleveland property mentioned in
paragraph 1 above has not been sold or the proceeds of such sale have
not been invested in such annuity contract prior to the date of
retirement, the amount of the deduction under this subparagraph B
shall be a life annuity determined by the Pension Plan actuaries to
be the actuarial equivalent of the projected value of the
Tax-adjusted BP Distribution, assuming those funds had been invested
at an annual rate of interest 1% greater than the average annual rate
of one-year U.S. Treasury bills in effect during the 12 months ending
on November 30th of each prior year (rounded up to the next
one-quarter percent, subject to a minimum annual rate of 5%),
compounded annually, from October 1, 1994, until the date of your
retirement, based on the mortality rates used under the Pension Plan
to determine actuarial equivalent values at the time of retirement,
and the interest rate which would be used by the Pension Benefit
Guaranty Corporation for purposes of determining the present value of
a lump sum distribution on plan termination as of January 1 of the
calendar year in which the retirement occurs, such amount to be
grossed up to reflect the fact that no income taxes would be payable
on the portion of an annuity derived from an initial after-tax
investment.
C. A life annuity determined by the Pension Plan actuaries to be
the actuarial equivalent of the projected value of the Non-taxable BP
Distribution, assuming those funds had been invested at an annual
rate of interest 1% greater than the average annual rate of one-year
U.S. Treasury bills in effect during the 12 months ending on November
30th of each prior year (rounded up to the next one-quarter percent,
subject to a minimum annual rate of 5%), compounded annually, from
October 1, 1994, until the date of your retirement, based on the
mortality rates used under the Pension Plan to determine actuarial
equivalent values at the time of retirement, and the interest rate
which would be used by the Pension Benefit Guaranty
2
<PAGE> 3
Mr. Michael W. Press November 2, 1994
Corporation for purposes of determining the present value of a lump
sum distribution on plan termination as of January 1 of the calendar
year in which the retirement occurs.
4. If you should die while employed by the Corporation under
circumstances in which a pre-retirement Qualified Joint and Survivor Annuity
would be payable to your surviving spouse under the Pension Plan, or after
retirement if a survivor benefit is payable, benefits will be paid to your
survivor under the PRP reduced by the deductions referred to above, all
calculated as of the earlier of the date of your death or retirement.
5. If your employment with the Corporation should terminate before you
are eligible to retire under the Pension Plan, benefits will be calculated
under the PRP formula taking into account your Prior Service for purposes of
computing Service and Credited Service, and reduced by the deductions
referred to above, all calculated as of the date your employment terminates.
This benefit will be paid to you by the Corporation commencing when you
reach age 65.
6. If you should die prior to retirement under the Pension Plan in
circumstances in which Pension Plan benefits would be payable to your
surviving spouse but for the lack of sufficient Service under the Pension
Plan, benefits will be calculated under the PRP formula and will be paid by
the Corporation by taking into account your Prior Service for purposes of
computing Service and Credited Service reduced by the deductions referred to
above, all calculated as of the date of your death.
For the purposes of paragraphs 3 through 6 above, Final Average Compensation
used for PRP benefit calculations as of any particular date, shall mean 12 times
your average monthly Compensation in such 36 consecutive calendar months during
the last 60 calendar months preceding said particular date which produces the
highest average Compensation, as those terms are defined in the Pension Plan. If
the particular date involved is less than 60 months after October 1, 1994, such
calculation shall include, to the extent necessary, the amount of your monthly
compensation that was used by BP to determine benefits under their various
retirement plans prior to October 1, 1994, with any lump sum bonus compensation
amounts prorated over the months of the calendar year to which such payments
applied. All benefits will be reduced for any payment prior to age 65 and
actuarially adjusted to reflect any form of payment other than an annuity for
your lifetime only, in accordance with the terms of the Pension Plan.
Nothing contained in the Pension Plan, PRP or this letter shall be construed as
a contract of employment or as changing the normal terms of the employment
relationship.
3
<PAGE> 4
Mr. Michael W. Press November 2, 1994
To qualify for the deferred compensation payments, you must sign and return the
enclosed copy of this letter by December 2, 1994. If you do not sign and return
the letter by then, the deferred compensation payments will not be made
available to you in the future.
The deferred compensation plan described above is unfunded for tax purposes and
for purposes of Title I of the Employee Retirement Income Security Act of 1974.
You would have the status of a general unsecured creditor of the Company with
respect to plan payments. The plan constitutes a mere promise to make benefit
payments in the future. Your rights with respect to any such payments would not
be subject in any manner to anticipation, alienation, sale, transfer,
assignment, pledge, encumbrance, attachment or garnishment by your creditors or
the creditors of your beneficiaries.
This letter will further confirm our agreement as to how we would unwind our
relationship in the unlikely, and unintended, event that it should not work out
to our mutual satisfaction. During the thee year period commencing October 1,
1994, either party may declare that the arrangement is not working out as
planned. In that event, you will receive as severance pay a lump-sum payment
equal to two times the amount of your then annual salary (less any required
deductions).
This agreement supersedes all prior agreements and understandings between us
relating to your employment with the Corporation.
Please indicate your acceptance of and agreement to the foregoing by signing the
enclosed copy of this letter in the space provided below and returning it to me.
Yours truly,
AMERADA HESS CORPORATION
/S/ Leon Hess
By: Leon Hess
Accepted and Agreed to by:
/S/ Michael W. Press 2 NOV 1994
-------------------- ----------
Michael W. Press Date
4
<PAGE> 1
UNITED STATES EXPLORATION AND PRODUCTION
During 1994, Amerada Hess was confronted by a significant drop in natural gas
prices. The Corporation responded to the lower prices by reducing production of
natural gas.
While Amerada Hess reduced capital expenditures, successful drilling
and positive reserve revisions, based on reservoir performance on properties
acquired in 1989 and on certain onshore properties, resulted in the Corporation
replacing 134% of its United States natural gas production and nearly all of its
United States liquids production in 1994.
OFFSHORE Amerada Hess drilled two successful exploration wells on Garden Banks
Blocks 259 and 260 (AHC 50%) in the Gulf of Mexico. These wells each encountered
approximately 200 feet of hydrocarbon-bearing sands. Two previous wells had
tested significant volumes of crude oil and natural gas. Early in 1995, a well
drilled on a separate structure to the north on Garden Banks Block 215 (AHC 50%)
encountered more than 150 feet of hydrocarbon-bearing sands. The Corporation is
evaluating potential development plans for this area, which is located in 1,650
feet of water.
Approximately six miles northeast of Block 215, an exploration well
discovered hydrocarbon-bearing sands in a subsalt prospect on Garden Banks Block
128 (AHC 25%). Amerada Hess is drilling an
AMERADA HESS MADE SIGNIFICANT HYDROCARBON DISCOVERIES AND INCREASED UNITED
STATES NATURAL GAS RESERVES.
6
<PAGE> 2
[Photo of West Cameron Block 498]
7
<PAGE> 3
[Photo of Carson Dome Field in Mississippi]
8
<PAGE> 4
exploration well on Garden Banks Block 172 (AHC 60%), the adjacent block to the
south. An exploration well also is being drilled on Garden Banks Block 127 (AHC
25%), the adjacent block to the west.
Amerada Hess drilled two successful wells on West Cameron Block 498
(AHC 57.42%). The initial well encountered 723 feet of crude oil and natural gas
sands. The second well encountered 150 feet of such sands. The Corporation has
acquired a three-dimensional seismic survey to determine the most economic
development plan prior to undertaking additional development drilling.
Predevelopment drilling for the South Pass Block 87 "D" platform (AHC
38%) has been completed. Four wells drilled in 1994 found oil and gas that will
be produced through the "D" platform. Production will begin in mid-1995 and peak
by year end at daily gross rates of 6,350 barrels of oil and 30,000 Mcf of
natural gas.
ONSHORE Amerada Hess completed development wells in both the Atchafalaya Bay
Field (AHC 100%) and the South Lewisburg Field (AHC 58%) in Louisiana. Combined
daily gross production from these wells will average 13,000 Mcf of natural gas
and 1,000 barrels of oil.
At the New Taiton prospect (AHC 100%), in Wharton County, Texas, the
Corporation drilled two wells that are producing 6,600 Mcf of natural gas and
160 barrels of oil per day. Additional drilling is underway.
In Mississippi, Amerada Hess drilled a discovery well in the
Carson Dome Field (AHC 75%). The well produced up to 4,400 Mcf of natural gas
and 560 barrels of oil per day. Three additional wells are planned for 1995. In
the Dry Creek Dome Field (AHC 75%) in Mississippi, the Corporation drilled two
wells that are producing a daily total of 5,000 Mcf of natural gas and 275
barrels of oil.
A NUMBER OF ONSHORE DISCOVERIES ARE ADDING TO NATURAL GAS DELIVERABILITY.
9
<PAGE> 5
INTERNATIONAL EXPLORATION AND PRODUCTION
UNITED KINGDOM Amerada Hess Limited, the Corporation's British subsidiary,
enjoyed a record year of hydrocarbon production in 1994, primarily due to the
first full year of production from the Scott Field and continued excellent
performance from the Ivanhoe/Rob Roy/Hamish Fields. Crude oil and natural gas
liquids production increased to 128,799 barrels per day from 83,802 barrels per
day in 1993. Natural gas production averaged 208,742 Mcf per day, despite
reduced demand late in the year due to warm weather, compared with 188,024 Mcf
per day in 1993.
Development of the Fife Field (AHL 85%) is on schedule for first oil in
September 1995. Gross production is expected to average 40,000 barrels per day.
Southeast of Fife, Amerada Hess Limited made a discovery called Fergus (AHL
65%), which will be appraised this year. Fergus is expected to be produced
through a tie-in to the floating production, storage and offloading vessel to be
used on Fife.
On Block 21/11 (AHL 28%), Amerada Hess Limited discovered the Dauntless
Field when an exploration well tested at 6,077 barrels of oil per day. Dauntless
is four miles northwest of the earlier discovery named Durward on adjacent Block
21/16 (AHL 28%), which tested at rates of over 4,300 barrels of oil per day.
Further appraisal drilling is planned to determine the full extent of reserves
in this area.
RECORD LEVELS OF PRODUCTION WERE ACHIEVED IN THE UNITED KINGDOM NORTH SEA.
10
<PAGE> 6
[Photo of Dauntless Field in the United Kingdom]
11
<PAGE> 7
[Photo of Ivanhoe/Rob Roy Field in the North Sea]
12
<PAGE> 8
In the emerging frontier area designated as West of Shetlands, Amerada
Hess Limited drilled a successful exploration well that extended the
Schiehallion Field onto Block 204/25a in which Amerada Hess Limited holds a
47.05% interest and is the operator. The well flowed at 5,300 barrels of oil per
day. Amerada Hess Limited also obtained approximately a 10% interest in the
undeveloped Clair Field when it acquired sole ownership of Blocks 206/12 and
206/13a. This acquisition and the Schiehallion discovery, together with earlier
discoveries made in 1990 and 1991 on Block 205/26a (AHL 42.07%), bring to four
the number of potentially commercial accumulations in which Amerada Hess Limited
has interests west of Shetlands. New exploration and further appraisal drilling
is planned for the area in 1995.
During 1994, Amerada Hess Limited reached an agreement to earn a 50%
interest in Blocks 15/16b and 14/20b, excluding the producing fields, in return
for an active exploration program. The blocks are adjacent to Block 15/21 (AHL
42.08%) on which the Ivanhoe/Rob Roy/Hamish Fields and a portion of the Scott
Field are located and will complement the Corporation's strategy in this area.
During 1994, Amerada Hess Limited sold its 6.83% interest in the Armada
Field resulting in a gain of $41 million.
NORWAY Amerada Hess Norge A/S, the Corporation's Norwegian subsidiary,
obtained its second operatorship offshore Norway, becoming operator on Block
2/12 (AHN 50%), which includes the Mjolner oil discovery. In 1995, Amerada Hess
Norge plans to drill its first operated well on Block 25/9 (AHN 20%).
Production from the Statfjord East Field (AHN 0.52%) and the Statfjord
North Field (AHN 1.04%) has begun. Peak production for Amerada Hess Norge from
these fields is estimated at an aggregate rate of approximately 1,000 barrels of
oil per day.
SIGNIFICANT CRUDE OIL DISCOVERIES WERE MADE WEST OF SHETLANDS.
13
<PAGE> 9
CANADA Amerada Hess Canada Ltd., the Corporation's Canadian subsidiary,
increased its natural gas production to 185,856 Mcf per day in 1994, from
167,839 Mcf per day in 1993. Amerada Hess Canada entered 1995 producing in
excess of 200,000 Mcf per day as a result of successful drilling and development
projects.
At Bezanson, Amerada Hess Canada completed construction of a 100%
owned, 20,000 Mcf per day natural gas plant and brought it on stream in
November. At Boundary Lake, successful drilling increased Amerada Hess Canada's
natural gas production in this area to 44,000 Mcf per day in 1994 from 31,000
Mcf per day in 1993.
Late in 1994, an exploration well (AHCL 100%) in the Bearberry Field
encountered natural gas in three zones and production tested at a total of
14,000 Mcf per day. Field compression facilities and new wells at Bearberry
added 25,000 Mcf per day of natural gas production, increasing gross Bearberry
Field deliverability to 75,000 Mcf per day.
GABON The Corporation's share of production from the Rabi Kounga Field in Gabon
averaged 8,746 barrels per day in 1994 compared with 8,136 barrels per day in
1993.
Amerada Hess, as operator with a 55% interest, has commenced
exploration studies prior to obtaining detailed seismic data for the Mazoumbel
permit area, which covers 573,534 gross acres in Gabon.
THAILAND Five successful delineation wells were drilled in the Pailin Field
(AHC 15%) offshore Thailand during 1994. Six delineation wells are planned for
1995 and negotiations for a natural gas sales contract have begun.
NATURAL GAS PRODUCTION IN CANADA INCREASED TO RECORD LEVELS.
14
<PAGE> 10
[Photo of Boundary Lake gas plant in Canada]
15
<PAGE> 11
[Photo of the Oxygenate Unit in St. Croix]
16
<PAGE> 12
REFINING AND MARKETING
REFINING The fluid catalytic cracking unit and associated gasoline upgrading
facilities constructed by Hess Oil Virgin Islands Corp., the Corporation's
Virgin Islands subsidiary (HOVIC), completed their first full year of operation
in 1994. The fluid catalytic cracking unit, which originally had a design
capacity of 75,000 barrels per day, ran at a rate of nearly 93,000 barrels per
day. The unit processes a feedstock composed of heavy gas oils and residual fuel
oil.
Early in 1995, HOVIC received a modification of its permit from the
Environmental Protection Agency that allows it to operate the facility at rates
in excess of 100,000 barrels per day. In the first quarter of 1995, the fluid
catalytic cracking unit tested successfully at 110,000 barrels per day.
The new facilities were major contributors to the turnaround in
refining and marketing results in 1994. The facilities have increased the
refinery's output of gasoline by more than 80,000 barrels per day and heating
oil by about 10,000 barrels per day.
The Virgin Islands refinery began shipping reformulated gasoline to the
East Coast of the United States early in November. Reformulated gasoline is sold
in nearly half of the Corporation's marketing area.
THE FLUID CATALYTIC CRACKING UNIT IN THE VIRGIN ISLANDS SUCCESSFULLY
TESTED AT RATES UP TO 110,000 BARRELS PER DAY.
17
<PAGE> 13
Refinery runs at HOVIC averaged 386,908 barrels per day in 1994
compared to 326,866 barrels per day in 1993. The increase in refinery runs
reflects the Corporation's ability to convert more of its product yield to
gasoline by virtue of its increased fluid catalytic cracking capacity. Fluid
catalytic cracking feedstock continues to be shipped from the Virgin Islands to
the Corporation's fluid catalytic cracking unit at Port Reading, New Jersey,
which runs at a rate of about 54,000 barrels per day.
MARKETING HESS brand gasoline stations are selling reformulated gasoline in all
of the Corporation's marketing areas where it is required. The transition to
reformulated gasoline was successfully made despite confusion by governmental
authorities in implementing the requirement. Of the Corporation's 541 HESS
gasoline stations, 203 sell reformulated gasoline.
During 1994, HESS gasoline stations began accepting credit cards in all
of the Corporation's marketing areas. Participating stations accept American
Express, Discover, MasterCard and Visa.
Amerada Hess began a program of marketing HESS brand gasoline through
contract dealers during 1994. This program is designed to increase the amount of
the Corporation's gasoline production marketed at retail under the HESS brand
name without requiring significant capital expenditures. This program will
continue in 1995.
Product sales increased to 468,000 barrels per day in 1994 from 386,000
barrels per day in 1993. Of the 1994 amount, 236,000 barrels per day were sales
of gasoline and premium diesel fuel. Residual fuel oil sales averaged 93,000
barrels per day, including residual fuel oil purchased for resale, or about 20%
of sales, the lowest percentage in the Corporation's history.
REFORMULATED GASOLINE IS BEING SOLD AT MANY HESS GASOLINE STATIONS.
18
<PAGE> 14
[Photo of a gasoline station in Three Bridges, New Jersey]
19
<PAGE> 15
FINANCIAL REVIEW
Amerada Hess Corporation and Consolidated Subsidiaries
Management's Discussion and Analysis of Results of Operations and Financial
Condition
CONSOLIDATED RESULTS OF OPERATIONS
Net income for 1994 amounted to $74 million ($.79 per share), compared with a
net loss of $268 million ($2.90 per share) in 1993 and net income of $8 million
($.09 per share) in 1992.
The results for 1994 include a net gain of $41 million ($.44 per share) from the
sale of the Corporation's interest in an undeveloped United Kingdom North Sea
natural gas field. The net loss for 1993 included after-tax charges aggregating
$55 million ($.59 per share) primarily for the mothballing of the Purvis,
Mississippi refinery, consolidation of United States exploration and production
operations in Houston and asset write-downs (see Note 2 to the financial
statements). The results for 1993 also included income of $29 million ($.32 per
share) from the cumulative effect of the change in accounting for income taxes
required by Statement of Financial Accounting Standards (FAS) No. 109,
Accounting for Income Taxes. Net income in 1992 included income of $25 million
($.29 per share) from the refund of prior years' income taxes and related
interest.
Sales and other operating revenues amounted to $6,602 million in 1994, an
increase of $722 million, or 12%, from 1993. The increase was primarily due to
higher refined product sales volumes, including an increased proportion of
gasoline sales. Foreign crude oil sales volumes were also higher, partially
offset by lower worldwide crude oil selling prices and the lower selling price
of domestic natural gas. Sales and other operating revenues in 1993 and 1992
were comparable. Foreign crude oil revenues and refined product revenues were
lower in 1993 than in 1992, offset by higher natural gas revenues, including
sales of purchased gas.
Non-operating revenues in 1994 were higher than in 1993, primarily because of
the sale of the United Kingdom natural gas field mentioned above. Non-operating
revenues in 1993 were lower than in 1992 because of a refinancing charge in 1993
and lower interest income (including interest on the income tax refund received
in 1992).
In each of the three years ended December 31, 1994, the Corporation's
consolidated effective income tax rate was higher than the U.S. statutory rate
of 35% (34% in 1992). This resulted primarily from higher income taxes on
foreign exploration and production earnings, including special taxes on
petroleum earnings, and income tax benefits which were not recorded in 1993 and
1992 on the losses of a refining subsidiary. The refining subsidiary had a
profit in 1994.
Following is a summary of net income (loss) by major operating activity (in
millions):
<TABLE>
<CAPTION>
-----------------------------------------------------------------------
1994 1993 1992
-----------------------------------------------------------------------
<S> <C> <C> <C>
Exploration and production $157 $116 $219
Refining and marketing 95 (293) (129)
Corporate administration,
including interest expense,
and other operating activities (178) (91) (82)
-----------------------------------------------------------------------
Total $74 $(268) $8
=======================================================================
</TABLE>
COMPARISON OF RESULTS
Exploration and Production: Exploration and production earnings in 1994 include
the gain of $41 million from the sale of the United Kingdom natural gas field.
In 1993, after-tax charges of $40 million were recorded primarily for the
consolidation of U.S. operations in Houston and the reduction in carrying value
of certain North Sea oil fields. Excluding these special items, exploration and
production earnings decreased by $40 million in 1994 compared with 1993.
Earnings from exploration and production activities in 1993 decreased by $63
million, excluding special items, compared with 1992 results.
Worldwide average crude oil selling prices declined in each of the three years.
The Corporation's average selling prices, including the effects of hedging, were
as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------
1994 1993 1992
------------------------------------------------------------------
<S> <C> <C> <C>
Crude oil and natural gas
liquids (per barrel)
United States $15.43 $17.40 $17.94
Foreign 15.91 16.89 19.40
Natural gas (per Mcf)
United States 1.91 2.11 1.76
Foreign 1.75 1.66 1.59
==================================================================
</TABLE>
In the latter part of 1994, and into 1995, U.S. and Canadian natural gas prices
were lower than the average price received in 1994.
21
<PAGE> 16
The Corporation's net daily worldwide production was as follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------
1994 1993 1992
-----------------------------------------------------------------
<S> <C> <C> <C>
Crude oil and natural gas
liquids (barrels per day)
United States 67,602 71,971 73,580
Foreign 182,918 143,419 150,607
-----------------------------------------------------------------
Total 250,520 215,390 224,187
-----------------------------------------------------------------
Natural gas (Mcf per day)
United States 427,103 502,459 601,824
Foreign 419,015 384,850 323,137
-----------------------------------------------------------------
Total 846,118 887,309 924,961
=================================================================
</TABLE>
The increase in foreign crude oil production in 1994 resulted primarily from a
full year of production from the Scott Field in the United Kingdom, which came
on stream in September 1993. United States natural gas production declined in
1994 and 1993 due to natural field decline and, in addition, voluntary
production curtailments in 1994, resulting from low natural gas prices.
Restrained exploration drilling in recent years, due to the allocation of
capital to the Corporation's major construction projects, inhibited the
exploration for new production to offset natural field declines. In both years,
foreign natural gas production increased because of higher production in Canada
and the United Kingdom. Natural gas production in the United Kingdom in 1994
included production from the Everest and Lomond natural gas fields (which
commenced in mid-1993) and the Scott Field.
Depreciation, depletion and amortization charges were higher in 1994,
principally reflecting increased United Kingdom crude oil and natural gas
production. Such charges are expected to continue at the higher level,
consistent with the increased production. Exploration expenses in 1994 and 1993
reflect the Corporation's overall objective of restraining capital spending, but
increased over 1992. Selling, general and administrative expenses in 1994 and
1993 reflect costs associated with the consolidation of United States
exploration and production operations in Houston. The effective income tax rate
on foreign exploration and production earnings is high because of the Petroleum
Revenue Tax in the United Kingdom and Special Tax in Norway.
While the Corporation's 1995 production of crude oil, natural gas liquids and
natural gas is anticipated to approximate 1994 levels, exploration and
production earnings will continue to be affected by changes in crude oil and
natural gas selling prices.
Refining and Marketing: Refining and marketing operations had income of $95
million in 1994 compared with losses of $293 million in 1993 and $129 million in
1992. The improvement in 1994 was due to higher refined product margins, the
operation of the fluid catalytic cracking unit in the Virgin Islands and
increased refinery runs. Although average refined product selling prices in 1994
approximated the 1993 level, the Corporation's average cost of crude oil
declined significantly in 1994. Earnings also benefited from the winter weather
in the early part of the year, which strengthened prices for distillates and
residual fuel oils. Gasoline selling prices continued to be weak in 1994,
reflecting competitive industry conditions. Depreciation expense was higher in
1994 because it was the first year of operation of the Virgin Islands fluid
catalytic cracking unit. Other refinery operating expenses were lower, primarily
because of the discontinuation of refining operations at the Purvis, Mississippi
refinery in early 1994. The refining and marketing loss in 1993 increased
compared with 1992, primarily because average refined product selling prices
declined by approximately $1.30 per barrel, which exceeded the decline in
average crude oil costs. Refinery operating expenses and depreciation expense
increased in 1993 compared with 1992. Income tax expense or benefit was not
recorded on a substantial portion of the 1994 income and the 1993 and 1992
losses of refining and marketing operations because of the net operating loss
carryforward of a refining subsidiary.
Total refined product sales volumes amounted to 171 million barrels in 1994, 141
million barrels in 1993 and 138 million barrels in 1992. Sales of gasoline were
higher in 1994, reflecting increased production from the Virgin Islands
refinery, including reformulated gasolines in late 1994. Distillate sales also
increased because of the weather in the early part of the year and the marketing
of premium diesel fuel.
Refining and marketing earnings will continue to be affected by competitive
industry conditions and supply and demand factors, including the effects of
22
<PAGE> 17
weather, in all refined product markets. As a result of increased gasoline
production, future profitability will be impacted to a greater extent than in
the past by the selling price of gasoline.
Corporate and Other: Corporate administration, including interest expense, and
other operating activities (principally transportation), had net expenses of
$178 million in 1994 compared with $91 million in 1993 and $82 million in 1992.
The increase in expenses in 1994 was due to higher interest expense, since
interest is no longer capitalized on the Corporation's major construction
projects, which were placed in service in late 1993. The results for 1993
included a benefit of $29 million from the adoption of FAS No. 109 and a charge
of $11 million in connection with a refinancing. The 1992 results included an
income tax refund and related interest of $25 million. Excluding special items,
net expenses were comparable in 1993 and 1992. Although the Corporation intends
to reduce debt further in 1995, interest expense may approximate or exceed the
1994 amount if interest rates remain at year-end levels or increase.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operating activities, including changes in operating assets
and liabilities, amounted to $957 million in 1994 compared with $819 million in
1993 and $1,138 million in 1992. The changes in each year were primarily due to
operating earnings and changes in components of working capital, including
inventories, receivables and payables. Cash provided by operating activities
exceeded capital expenditures of $596 million in 1994 and the excess cash flow
was used primarily to repay debt. In 1993 and 1992, capital expenditures
exceeded net cash provided by operating activities, largely reflecting spending
by the Corporation on its major North Sea projects and the upgrading of the
Virgin Islands refinery. The additional spending was financed principally by
long-term borrowings and the issuance of 11,500,000 shares of common stock in
1992.
Total debt was $3,340 million at December 31, 1994 compared with $3,688 million
at December 31, 1993. The debt to total capitalization ratio was 52% at December
31, 1994 compared with nearly 55% at year-end 1993. The Corporation anticipates
that total debt will decline further in 1995.
At December 31, 1994, the Corporation had additional borrowing capacity
available under existing revolving credit agreements of $465 million and
additional unused lines of credit under uncommitted arrangements with banks of
$657 million.
In the fourth quarter of 1994, the Corporation refinanced its revolving credit
facilities in the United States and the United Kingdom. The new facilities have
an aggregate capacity of $2,200 million. Borrowings had been due principally in
1996 and 1997, whereas, amounts outstanding under the new facilities will be due
in 1999 and thereafter. In several other transactions during 1994, the
Corporation issued approximately $300 million of fixed-rate debt. Proceeds were
used to retire existing higher-rate long-term debt and to repay revolving credit
borrowings. The Corporation's borrowing arrangements, including restrictive
covenants, are more fully described in Note 5 to the financial statements.
As part of a proposed 1995 combination of two United Kingdom independent oil and
gas companies, the Corporation agreed to exchange its 48% common stock interest
in Pict Petroleum plc for an interest in the United Kingdom independent oil and
gas company with which Pict will be combined. The Corporation also agreed to
increase its equity interest in the combined entity to approximately 25%, by
subscribing to purchase newly issued shares for approximately $30 million.
The Corporation uses futures, forward, option and swap contracts, generally with
maturities of one year or less, to reduce the effects of fluctuations in the
prices of crude oil, natural gas and refined products. These instruments are
used to set the selling and purchase prices of crude oil, natural gas and
refined products and the related gains or losses are an integral part of the
Corporation's selling prices and costs. At December 31, 1994, the Corporation
had open hedge positions, primarily futures contracts, on approximately 25% of
its estimated 1995 worldwide crude oil production at an average price of
approximately $17.80 per barrel and had option contracts, providing varying
degrees of protection against declines in market prices, covering an additional
5% of crude oil production. The Corporation also had open futures contracts and
swap positions on approximately 60% of its estimated 1995 United States and
Canadian natural gas production at an average price of approximately $1.75 per
Mcf and, in
23
<PAGE> 18
addition, had option contracts, providing varying degrees of price protection,
covering approximately 20% of its natural gas production. The Corporation had
hedges (primarily futures, swaps and options) covering approximately 35% of its
refining and marketing inventories at an average price of approximately $.60 per
barrel over year-end market prices and had additional short positions,
principally crack spreads, approximating 10% of refined products to be
manufactured in the next twelve months. As market conditions change, the
Corporation will adjust its hedging positions. Year-end hedge positions are not
necessarily indicative of future results of operations.
At December 31, 1994, the Corporation also had outstanding interest rate
conversion agreements that reduce the percentage of its floating rate debt to
total debt from 54% to 47%. The effect of these agreements is accounted for as a
component of interest expense. The Corporation also periodically hedges foreign
currency transactions. See Note 12 to the financial statements for additional
information on the Corporation's hedging activities.
The Corporation conducts foreign exploration and production activities,
principally in the United Kingdom, Norway, Canada and Gabon, and, therefore, is
subject to business risks associated with foreign operations, including the
effect of foreign currency gains and losses on reported earnings. However,
foreign crude oil sales revenue generally is denominated in United States
dollars, which tends to mitigate economic exposure to the Corporation. Most
expenditures, including income taxes, are denominated in the foreign currencies.
The Corporation records foreign currency gains or losses on the U.S. dollar
denominated net monetary assets or liabilities of certain foreign subsidiaries,
in accordance with FAS No. 52. Such gains or losses have not been material to
consolidated net income. Also, as required by FAS No. 52, the effect of a
stronger U.S. dollar over a number of years, principally on the translation of
property, plant and equipment, has been recorded as a reduction of stockholders'
equity. This equity adjustment has not affected the Company's liquidity or
ability to raise capital. The magnitude of any such adjustments in the future
depends on the degree of fluctuation in exchange rates.
CAPITAL EXPENDITURES
The Corporation's capital expenditures decreased in 1994, after the completion
of major projects in the United Kingdom and Virgin Islands. These projects were
the development of the Scott oil field and the Everest and Lomond natural gas
fields and Central Area Transmission System in the United Kingdom North Sea,
and the construction of the fluid catalytic cracking complex and associated
gasoline upgrading facilities at the Virgin Islands refinery.
The following table summarizes the Corporation's capital expenditures in 1994,
1993 and 1992 (in millions):
<TABLE>
<CAPTION>
------------------------------------------------------------------------
1994 1993 1992
------------------------------------------------------------------------
<S> <C> <C> <C>
Exploration and production
Intangible drilling costs, equipment
and related facilities
United States $216 $ 241 $ 168
Foreign 294 458 710
Lease acquisitions 18 40 26
Purchases of oil and gas reserves 3 16 12
------------------------------------------------------------------------
531 755 916
Refining and marketing 62 591 639
Transportation and other 3 2 3
------------------------------------------------------------------------
Total $596 $1,348(*) $1,558(*)
========================================================================
</TABLE>
(*)Includes expenditures for major projects of $722 million and $1,043 million
in 1993 and 1992, respectively.
Capital expenditures in 1995 are presently expected to be approximately $700
million and will be financed by internally generated funds.
ENVIRONMENT, HEALTH AND SAFETY
The Corporation's awareness of its environmental responsibilities, along with
increasing environmental regulations at the federal, state and local levels,
have led to programs requiring higher operating costs and capital investments by
the Corporation. The Corporation believes that environmental, health and safety
expenditures will increase in the future, as pollution prevention and
remediation laws are implemented.
The Corporation continues to implement and improve its environment, health and
safety program. This program includes pollution control and reduction, waste
minimization and treatment, compliance evaluation, facility auditing and
employee training to monitor operational conditions and prevent non-compliant
activities that might threaten the environment. The Corporation has also
significantly increased its environment, health and safety staffing.
24
<PAGE> 19
The Corporation produces gasolines that meet the requirements for oxygenated and
reformulated gasolines under the Clean Air Act of 1990. Reformulated gasolines,
which decrease emissions of volatile and toxic organic compounds, were required
in designated areas commencing in January 1995. The Corporation is producing
reformulated gasolines that meet these requirements at both the Virgin Islands
and Port Reading facilities. The Corporation's Virgin Islands refinery also has
desulfurization capabilities enabling it to produce low-sulfur diesel fuel that
meets the requirements of the Clean Air Act. The Corporation will continue
upgrading its facilities to meet regulatory changes.
The Corporation expects that there will continue to be future expenditures for
assessment and remediation. Sites where corrective action may be necessary
include gasoline stations, terminals, refineries (including solid waste
management units under permits issued pursuant to the Resource Conservation and
Recovery Act) and, although not significant, Superfund sites where the
Corporation has been named a potentially responsible party under the Superfund
legislation. The Corporation expects that existing reserves for environmental
liabilities will adequately cover costs of assessing and remediating known
environmental sites.
The Corporation expended $16 million in 1994, $14 million in 1993 and $16
million in 1992 for remediation, mostly in its refining and marketing activity.
In addition, capital expenditures for facilities, primarily to comply with
federal, state and local environmental standards, were $8 million in 1994, $28
million in 1993 and $10 million in 1992.
DIVIDENDS
Cash dividends on common stock totaled $.60 per share ($.15 per quarter) during
1994 and 1993.
STOCK MARKET INFORMATION
The common stock of Amerada Hess Corporation is traded principally on the New
York Stock Exchange (ticker symbol: AHC). High and low sales prices in 1994 and
1993 were as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------
1994 1993
----------- -----------
Quarter ended High Low High Low
------------------------------------------------------------------------
<S> <C> <C> <C> <C>
March 31 49-7/8 44-5/8 53-3/8 43-5/8
June 30 52-1/4 44 56-3/8 48
September 30 52-5/8 45-1/8 54-1/2 46-5/8
December 31 50-1/4 43-7/8 54-3/4 42-3/8
========================================================================
</TABLE>
QUARTERLY FINANCIAL DATA
Quarterly results of operations for the years ended December 31, 1994 and 1993
follow (millions of dollars, except per share data):
<TABLE>
<CAPTION>
----------------------------------------------------------------
Sales and Net
other Net income
operating Gross income (loss)
Quarter revenues profit(a) (loss) per share
----------------------------------------------------------------
<S> <C> <C> <C> <C>
1994
First $1,858 $422 $84 $.90
Second 1,488 270 (17) (.18)
Third 1,494 262 (2)(b) (.02)
Fourth 1,762 318 9 .09
----------------------------------------------------------------
Total $6,602 $1,272 $74 $.79
================================================================
1993
First $1,565 $273 $33(c) $.36
Second 1,415 135 (145)(d) (1.57)
Third 1,249 262 (22) (.24)
Fourth 1,651 153 (134)(e) (1.45)
----------------------------------------------------------------
Total $5,880 $823 $(268) $(2.90)
================================================================
</TABLE>
(a) Gross profit represents sales and other operating revenues less cost of
products sold and operating expenses and depreciation, depletion and
amortization.
(b) Includes a net gain of $41 million from the sale of an interest in an
undeveloped United Kingdom natural gas field.
(c) Includes income of $29 million from the cumulative effect of the change in
accounting for income taxes required by FAS No. 109.
(d) Includes a charge of $80 million for the write-down to market value of
refining and marketing inventories.
(e) Reflects special charges aggregating $55 million (see Note 2 to the
financial statements).
The results of operations for the periods reported herein should not be
considered as indicative of future operating results.
25
<PAGE> 20
CONSOLIDATED BALANCE SHEET
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
At December 31
---------------------------
Thousands of dollars 1994 1993
--------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 53,135 $ 79,635
Accounts receivable
Trade 546,341 506,825
Other 24,184 48,162
Inventories 945,635 853,393
Prepaid expenses 152,366 200,151
--------------------------------------------------------------------------------------------------------------
Total current assets 1,721,661 1,688,166
--------------------------------------------------------------------------------------------------------------
Investments and Advances 140,300 137,161
--------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Exploration and production 9,656,923 9,227,937
Refining 3,005,198 2,994,881
Marketing 887,526 839,793
Transportation 715,407 685,818
Other 39,772 38,811
--------------------------------------------------------------------------------------------------------------
Total--at cost 14,304,826 13,787,240
Less reserves for depreciation, depletion, amortization and lease impairment 7,938,824 7,052,328
--------------------------------------------------------------------------------------------------------------
Property, plant and equipment--net 6,366,002 6,734,912
--------------------------------------------------------------------------------------------------------------
Other Assets 109,977 81,307
--------------------------------------------------------------------------------------------------------------
Total Assets $ 8,337,940 $ 8,641,546
==============================================================================================================
</TABLE>
26
<PAGE> 21
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
At December 31
-------------------------
1994 1993
------------------------------------------------------------------------------------------------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable--trade $ 291,571 $ 329,648
Accrued liabilities 533,640 613,791
Deferred revenue 21,723 128,566
Notes payable 63,747 117,900
Taxes payable 168,927 106,893
Current maturities of long-term debt 121,806 146,342
------------------------------------------------------------------------------------------------
Total current liabilities 1,201,414 1,443,140
------------------------------------------------------------------------------------------------
LONG-TERM DEBT 3,154,235 3,423,680
------------------------------------------------------------------------------------------------
CAPITALIZED LEASE OBLIGATIONS 80,928 91,094
------------------------------------------------------------------------------------------------
DEFERRED LIABILITIES AND CREDITS
Deferred income taxes 547,537 462,273
Other 254,197 192,448
------------------------------------------------------------------------------------------------
Total deferred liabilities and credits 801,734 654,721
------------------------------------------------------------------------------------------------
STOCKHOLDERS' EQUITY
Preferred stock, par value $1.00
Authorized--20,000,000 shares for issuance in series -- --
Common stock, par value $1.00
Authorized--200,000,000 shares
Issued--92,995,755 shares in 1994; 92,586,855 shares in 1993 92,996 92,587
Capital in excess of par value 743,537 725,443
Retained earnings 2,467,267 2,449,325
Equity adjustment from foreign currency translation (204,171) (238,444)
------------------------------------------------------------------------------------------------
Total stockholders' equity 3,099,629 3,028,911
------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $8,337,940 $8,641,546
================================================================================================
</TABLE>
The consolidated financial statements reflect the successful efforts method of
accounting for oil and gas exploration and producing activities.
See accompanying notes to consolidated financial statements.
27
<PAGE> 22
STATEMENT OF CONSOLIDATED INCOME
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
For the Years Ended December 31
---------------------------------------
Thousands of dollars, except per share data 1994 1993 1992
--------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES
Sales (excluding excise taxes) and other operating revenues $6,601,984 $5,879,521 $5,858,357
Interest and other non-operating revenues 96,809 21,153 95,352
--------------------------------------------------------------------------------------------------------
Total revenues 6,698,793 5,900,674 5,953,709
--------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Cost of products sold and operating expenses 4,449,819 4,287,139 4,039,180
Exploration expenses, including dry holes 249,433 258,826 228,998
Selling, general and administrative expenses 590,647 596,919 581,542
Interest expense 245,149 156,615 147,099
Depreciation, depletion and amortization 879,679 769,390 773,507
Lease impairment 48,254 55,261 59,898
Provision for income taxes 162,098 74,186 115,940
--------------------------------------------------------------------------------------------------------
Total costs and expenses 6,625,079 6,198,336 5,946,164
--------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 73,714 (297,662) 7,545
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR INCOME TAXES -- 29,459 --
--------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 73,714 $ (268,203) $ 7,545
========================================================================================================
NET INCOME (LOSS) PER SHARE BEFORE ACCOUNTING CHANGE $ .79 $ (3.22) $ .09
========================================================================================================
NET INCOME (LOSS) PER SHARE $ .79 $ (2.90) $ .09
========================================================================================================
</TABLE>
STATEMENT OF CONSOLIDATED RETAINED EARNINGS
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
For the Years Ended December 31
---------------------------------------
Thousands of dollars, except per share data 1994 1993 1992
--------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $2,449,325 $2,773,018 $2,817,507
Net income (loss) 73,714 (268,203) 7,545
Dividends declared--common stock
($.60 per share in 1994, 1993 and 1992) (55,772) (55,490) (52,034)
--------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR $2,467,267 $2,449,325 $2,773,018
========================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
28
<PAGE> 23
STATEMENT OF CONSOLIDATED CASH FLOWS
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
For the Years Ended December 31
----------------------------------------
Thousands of dollars 1994 1993 1992
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 73,714 $ (268,203) $ 7,545
Adjustments to reconcile net income (loss) to net cash provided
by operating activities
Depreciation, depletion, amortization and lease impairment 927,933 824,651 833,405
Exploratory dry hole costs 152,971 155,725 135,067
(Increase) decrease in accounts receivable (15,927) 201,290 397,975
(Increase) decrease in inventories (90,258) 127,990 (16,735)
Decrease in accounts payable, accrued liabilities and
deferred revenue (191,282) (154,257) (220,604)
Increase (decrease) in taxes payable 62,437 (8,980) 28,749
Changes in deferred income taxes and other 37,430 (58,793) (27,695)
------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 957,018 819,423 1,137,707
------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
Exploration and production (531,409) (754,876) (915,476)
Refining and marketing (62,238) (591,545) (639,365)
Transportation and other (2,637) (1,620) (2,953)
------------------------------------------------------------------------------------------------------------
Total capital expenditures (596,284) (1,348,041) (1,557,794)
Other, including proceeds from sales of property,
plant and equipment 72,804 12,436 25,423
------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (523,480) (1,335,605) (1,532,371)
------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance (repayment) of notes (54,153) 117,791 (159,756)
Long-term borrowings 289,843 547,704 675,016
Repayment of long-term debt and capitalized lease obligations (642,112) (167,769) (524,384)
Issuance of common stock -- -- 497,360
Cash dividends paid (55,711) (41,603) (64,194)
------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (462,133) 456,123 424,042
------------------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH 2,095 (1,320) (8,534)
------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (26,500) (61,379) 20,844
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 79,635 141,014 120,170
------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 53,135 $79,635 $ 141,014
============================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
29
<PAGE> 24
STATEMENT OF CONSOLIDATED CHANGES IN COMMON STOCK AND CAPITAL IN EXCESS OF PAR
VALUE
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
Common stock
----------------------- Capital in
Number of excess of
Thousands of dollars shares Amount par value
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
BALANCE AT JANUARY 1, 1992 81,067,835 $81,068 $239,696
Issuance of common stock 11,500,000 11,500 485,860
Cancellations under executive incentive
compensation and stock ownership plan (net) (8,500) (8) (391)
Employee stock options exercised 24,367 24 503
-------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1992 92,583,702 92,584 725,668
Cancellations under executive incentive
compensation and stock ownership plan (net) (17,000) (17) (589)
Employee stock options exercised 20,153 20 364
-------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1993 92,586,855 92,587 725,443
Distribution to trustee under executive incentive
compensation and stock ownership plan (net) 408,900 409 18,094
-------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1994 92,995,755 $92,996 $743,537
=================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
30
<PAGE> 25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amerada Hess Corporation and Consolidated Subsidiaries
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation: The consolidated financial statements include the
accounts of Amerada Hess Corporation and subsidiaries (the "Corporation"). The
Corporation's interests in oil and gas exploration and production ventures are
proportionately consolidated.
Investments in affiliated companies, owned 20% to 50% inclusive, are stated at
cost of acquisition plus the Corporation's equity in undistributed net income
since acquisition. The change in the equity in net income of these companies is
included in non-operating revenues in the Statement of Consolidated Income.
Intercompany transactions and accounts are eliminated in consolidation.
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.
Inventories: Crude oil and refined product inventories are valued at the lower
of cost or market value. Cost is determined on the first-in, first-out method
for approximately 60% of the inventories and the average cost method for the
remainder.
Inventories of materials and supplies are valued at or below cost.
Exploration and Development Costs: Oil and gas exploration and producing
activities are accounted for on the successful efforts method. Costs of
acquiring undeveloped oil and gas leasehold acreage, including lease bonuses,
brokers' fees and other related costs, are capitalized. Provisions for
impairment of undeveloped oil and gas leases are based on periodic evaluations
and other factors.
Annual lease rentals and exploration expenses, including geological and
geophysical expenses and exploratory dry hole costs, are charged against income
as incurred.
Costs of drilling and equipping productive wells, including development dry
holes, and related production facilities are capitalized.
Depreciation, Depletion and Amortization: Depreciation, depletion and
amortization of oil and gas production equipment, properties and wells are
determined on the unit-of-production method based on estimated recoverable oil
and gas reserves. Depreciation of refinery facilities is determined on the
unit-of-production method based on estimated thruput volumes. Depreciation of
all other plant and equipment is determined on the straight-line method based on
estimated useful lives.
The estimated costs of dismantlement, restoration and abandonment, less
estimated salvage values, of offshore oil and gas production platforms and
certain other facilities are taken into account in determining depreciation.
Retirement of Property, Plant and Equipment: Costs of property, plant and
equipment retired or otherwise disposed of, less accumulated reserves, are
reflected in net income.
Maintenance and Repairs: The estimated costs of major maintenance, including
turnarounds at refineries, are accrued. Other expenditures for maintenance and
repairs are charged against income as incurred. Renewals and improvements are
treated as additions to property, plant and equipment, and items replaced are
treated as retirements.
Environmental Expenditures: The Corporation capitalizes environmental
expenditures that increase the life or efficiency of property or that reduce or
prevent environmental contamination that has yet to occur. The Corporation
accrues for environmental expenses resulting from existing conditions that
relate to past operations when the costs are probable and reasonably estimable.
Foreign Currency Translation: The local currency is the functional currency
(primary currency in which business is conducted) for the Corporation's North
Sea and Canadian operations. The U.S. dollar is the functional currency for
other foreign operations. Adjustments resulting from translating foreign
functional currency assets and liabilities into U.S. dollars are recorded in a
separate component of stockholders' equity entitled "Equity adjustment from
foreign currency translation." Gains or losses resulting from transactions in
other than the functional currency are reflected in net income.
31
<PAGE> 26
Hedging: The Corporation hedges the effects of fluctuations in the prices of
crude oil, natural gas and refined products, interest rates and the exchange
rates of foreign currencies. The resulting gains or losses, measured by quoted
market prices, termination values or other methods, are accounted for as part of
the transactions being hedged, except that losses not expected to be recovered
upon the completion of hedged transactions are expensed. On the balance sheet,
deferred gains are included in deferred revenue at December 31, 1994 and 1993.
Income Taxes: Deferred income taxes are determined on the liability method in
accordance with Statement of Financial Accounting Standards (FAS) No. 109.
No provision is made for U.S. income taxes applicable to undistributed earnings
of foreign subsidiaries that are indefinitely reinvested in foreign operations.
2. 1993 SPECIAL CHARGES
During the fourth quarter of 1993, the Corporation recorded special charges,
including asset write-downs, amounting to $78,900,000 ($54,500,000 after income
taxes). Of this amount, $56,600,000 ($40,000,000 after income taxes) related to
consolidating U.S. exploration and production activities and offices, reducing
the carrying value of certain North Sea oil properties and surrendering an
operated joint venture in Abu Dhabi. The remainder represented costs associated
with mothballing the Purvis, Mississippi refinery. In total, fixed assets were
reduced by $39,200,000. The charges other than fixed asset reductions were
primarily for relocation, severance, and related expenses, substantially all of
which were included in selling, general and administrative expenses.
3. INVENTORIES
Inventories at December 31 are as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------
Thousands of dollars 1994 1993
---------------------------------------------------------------------
<S> <C> <C>
Crude oil and other charge stocks $250,291 $299,015
Refined and other finished products 582,696 436,633
---------------------------------------------------------------------
832,987 735,648
Materials and supplies 112,648 117,745
---------------------------------------------------------------------
Total $945,635 $853,393
=====================================================================
</TABLE>
4. SHORT-TERM NOTES PAYABLE AND RELATED LINES OF CREDIT
Short-term notes payable to banks at December 31, 1994 amount to $63,747,000
compared to $117,900,000 at December 31, 1993. The weighted average interest
rates on these borrowings were 6.2% and 3.8% at December 31, 1994 and 1993,
respectively. At December 31, 1994, the Corporation has unused lines of credit
under uncommitted arrangements with several banks aggregating approximately
$657,000,000. No compensating balances or fees are required for such lines of
credit.
5. LONG-TERM DEBT
Long-term debt at December 31 consists of the following:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------
Thousands of dollars 1994 1993
--------------------------------------------------------------------------
<S> <C> <C>
6.1% Marine Terminal Revenue Bonds--
Series 1994--City of Valdez, Alaska,
due 2024 $ 20,000 $ 20,000
Pollution Control Revenue Bonds with
sinking fund requirements, weighted
average rate 6.6%,* due through 2022 52,541 52,686
Fixed rate notes, payable principally to
insurance companies, weighted average
rate 8.8%, due through 2014 1,461,815 1,219,979
Revolving Credit Agreement with banks,
weighted average rate 6.9%,* due 1999 1,043,749 1,157,789
Revolving Credit Agreement with banks,
weighted average rate 7.0%,* due
through 2002 547,222 939,710
Revolving Credit Agreement with banks,
weighted average rate 6.7%,
due through 1998 112,000 126,000
Other loans, weighted average rate 8.2%,
due through 2007 38,714 53,858
--------------------------------------------------------------------------
3,276,041 3,570,022
Less amount included in current
maturities 121,806 146,342
--------------------------------------------------------------------------
Total $3,154,235 $3,423,680
==========================================================================
</TABLE>
*Includes effect of interest rate conversion agreements.
32
<PAGE> 27
The aggregate long-term debt maturing during the next five years is as follows
(in thousands): 1995--$121,806 (included in current liabilities);
1996--$159,642; 1997--$254,879; 1998--$133,679 and 1999--$1,205,686.
Of the total long-term debt at December 31, 1994, including current maturities,
$25,355,000 was secured by assets with a net book value of $22,297,000.
The Corporation's long-term debt agreements contain various restrictions and
conditions, including the requirement to maintain a ratio of current assets to
current liabilities of not less than 1 to 1. There are also limitations on total
borrowings under the agreements. In addition, the cumulative amount of cash
dividends and stock distributions (as defined), under the most restrictive
covenant, may not exceed consolidated net income (as defined) subsequent to
December 31, 1990, plus $600,000,000. At December 31, 1994, the ratio of current
assets to current liabilities is 1.4 to 1 and the Corporation has additional
allowable borrowing capacity for the construction or acquisition of assets of
$465,000,000. Retained earnings free of restrictions at December 31, 1994 amount
to $285,000,000.
At December 31, 1994, the Corporation has Revolving Credit Agreements with banks
aggregating $1,400,000,000 ($1,043,749,000 outstanding at December 31, 1994),
which are due to be repaid in 1999. Borrowings bear interest based on various
money market rates chosen by the Corporation. Commitment fees of .2% per annum
are payable on the unused portion of the credit lines.
A wholly-owned subsidiary of the Corporation operating in the United Kingdom has
a multi-currency Revolving Credit Agreement (the "United Kingdom Facility") with
banks aggregating $800,000,000 ($547,222,000 outstanding at December 31, 1994),
which declines each year from 1999 through 2002. The United Kingdom Facility
bears interest at .425% above the London Interbank Offered Rate (LIBOR).
Commitment fees of .188% per annum are payable on the unused portion of the
credit lines.
A wholly-owned subsidiary of the Corporation operating in Canada has a
dual-currency Revolving Credit Agreement (the "Canada Facility") with banks
aggregating $150,000,000 ($112,000,000 outstanding at December 31, 1994). The
amount available under the Canada Facility declines ratably each year through
1998. Borrowings bear interest at .75% above LIBOR. Commitment fees of .25% per
annum are payable on the unused portion of the credit lines.
A wholly-owned subsidiary of the Corporation operating in Norway has a Revolving
Credit Agreement (the "Norway Facility") with banks aggregating $20,000,000. No
borrowings are outstanding at December 31, 1994. The Norway Facility terminates
in 1995. Commitment fees of .25% per annum are payable on the unused portion of
the credit lines.
At December 31, 1994, the Corporation has interest rate conversion agreements,
which effectively reduce the percentage of its floating rate debt from 54% to
47%.
The total amount of interest paid (net of amounts capitalized), principally on
short-term and long-term debt, in 1994, 1993 and 1992 was $248,595,000,
$169,277,000 and $139,705,000, respectively.
6. Stockholders' Equity
At December 31, 1994, the number of shares of common stock reserved for issuance
is as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------
<S> <C>
Future distributions under the Executive Long-Term
Incentive Compensation and Stock Ownership Plan 232,500
Warrants* 1,044,354
---------------------------------------------------------------------------
Total 1,276,854
===========================================================================
</TABLE>
*Exercisable through June 27, 2001 at $65.11 per share.
33
<PAGE> 28
7. Foreign Currency Translation
Foreign currency exchange transactions reflected in net income (after income tax
effect) amounted to losses of $931,000 in 1994, $1,788,000 in 1993 and $707,000
in 1992.
The equity adjustment from foreign currency translation, included as a component
of stockholders' equity, reflected gains of $34,273,000 in 1994 and losses of
$34,773,000 in 1993. The cumulative translation adjustments at December 31
consist of:
<TABLE>
<CAPTION>
----------------------------------------------------------------------
Thousands of dollars 1994 1993
----------------------------------------------------------------------
<S> <C> <C>
Working capital $ 36,424 $ 40,786
Property, plant and equipment, net (392,586) (490,033)
Long-term debt 77,967 91,749
Deferred income taxes 23,569 45,874
Other items 50,455 73,180
----------------------------------------------------------------------
Total $(204,171) $(238,444)
======================================================================
</TABLE>
8. Pension Plans
The Corporation has non-contributory defined benefit pension plans covering
substantially all employees, except those covered by union pension plans.
Retirement benefits are based on credited service and final average
compensation. The Corporation's policy is to fund pension costs accrued, except
where funding limitations are imposed under income tax regulations.
Pension expense consisted of:
<TABLE>
<CAPTION>
------------------------------------------------------------------------
Thousands of dollars 1994 1993 1992
------------------------------------------------------------------------
<S> <C> <C> <C>
Cost of benefits earned $ 24,119 $ 21,540 $ 14,890
Accrued interest on
projected benefit
obligation 24,080 21,859 21,106
Loss (return) on plan assets 9,326 (35,053) (19,384)
Net amortization and
deferral (36,860) 10,082 (4,812)
------------------------------------------------------------------------
Total $ 20,665 $ 18,428 $ 11,800
========================================================================
</TABLE>
Plan assets include fixed income and equity securities, including investments in
commingled funds. A summary of the funded status of the Corporation's pension
plans at December 31 follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------
Thousands of dollars 1994 1993
------------------------------------------------------------------------------
<S> <C> <C>
Market value of plan assets $289,294 $308,683
------------------------------------------------------------------------------
Actuarial present value of benefit obligation
Vested 279,374 264,076
Non-vested 3,585 3,112
------------------------------------------------------------------------------
Total 282,959 267,188
Effect of projected future salary increases 53,063 63,101
------------------------------------------------------------------------------
Projected benefit obligation 336,022 330,289
------------------------------------------------------------------------------
Projected benefit obligation in excess of
plan assets $(46,728) $(21,606)
------------------------------------------------------------------------------
Components of projected benefit obligation
in excess of plan assets
Unrecognized prior service costs $ (4,923) $ (7,960)
Unrecognized net experience losses (15,748) (4,387)
Unrecognized net transitional asset 8,140 11,494
Accrued pension cost (34,197) (20,753)
------------------------------------------------------------------------------
Total $(46,728) $(21,606)
==============================================================================
</TABLE>
The discount rate and assumed rate of future salary increases used in
determining the actuarial present value of the projected benefit obligation were
8% and 6%, respectively, in 1994 and 7% and 6%, respectively, in 1993. The
expected long-term rate of return on plan assets in 1994 and 1993 was 8%.
The Corporation has non-qualified supplemental pension plans covering certain
employees, which provide for incremental pension payments from the Corporation's
funds so that total pension payments equal amounts that would have been payable
from the Corporation's principal pension plans if it were not for limitations
imposed by income tax regulations. The projected benefit obligation relating to
these unfunded plans totaled $17,979,000 at December 31, 1994 and $17,025,000 at
December 31, 1993. Pension expense for the plans was $3,871,000 in 1994,
$1,823,000 in 1993 and $1,771,000 in 1992.
34
<PAGE> 29
9. CAPITALIZATION OF INTEREST
No interest expense was capitalized in 1994. Capitalized interest amounted to
$92,228,000 in 1993 and $108,095,000 in 1992.
10. PROVISION FOR INCOME TAXES
The provision for income taxes consisted of:
<TABLE>
<CAPTION>
------------------------------------------------------------------------
Thousands of dollars 1994 1993 1992
------------------------------------------------------------------------
<S> <C> <C> <C>
United States Federal
Current $ (350) $ 15,380 $ 5,352(c)
Deferred (39,948)(a) (72,040) (21,701)
State 1,666 1,552 1,891
------------------------------------------------------------------------
(38,632) (55,108) (14,458)
------------------------------------------------------------------------
Foreign
Current 131,107 93,895 109,406
Deferred 69,623 41,272 31,772
------------------------------------------------------------------------
200,730 135,167 141,178
------------------------------------------------------------------------
Adjustment of deferred tax
liability for income tax
rate changes -- (5,873) (10,780)
------------------------------------------------------------------------
Total $162,098 $ 74,186(b) $115,940
========================================================================
</TABLE>
(a) Includes benefit of operating loss of $43,121.
(b) Excludes benefit of $29,459 as of January 1, 1993, from the cumulative
effect of the change in accounting for income taxes required by FAS 109.
(c) Includes $11,220 from the refund of prior years' income taxes.
Income (loss) before income taxes consisted of the following:
<TABLE>
<CAPTION>
------------------------------------------------------------------
Thousands of dollars 1994 1993 1992
------------------------------------------------------------------
<S> <C> <C> <C>
United States $(170,813) $(190,726) $ 12,482
Foreign* 406,625 (32,750) 111,003
------------------------------------------------------------------
Total $ 235,812 $(223,476) $123,485
==================================================================
</TABLE>
*Foreign income includes the Corporation's Virgin Islands, shipping and other
operations located outside of the United States.
Deferred income taxes arise from temporary differences between the tax basis of
assets and liabilities and their reported amounts in the financial statements. A
summary of the components of deferred tax liabilities and assets at December 31
follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------
Thousands of dollars 1994 1993
--------------------------------------------------------------------------
<S> <C> <C>
Deferred tax liabilities
Fixed assets $ 580,651 $ 549,328
Foreign petroleum taxes 184,033 135,483
Other items 84,254 93,784
--------------------------------------------------------------------------
Total deferred tax liabilities 848,938 778,595
--------------------------------------------------------------------------
Deferred tax assets
Accrued liabilities 123,619 133,682
Net operating and other loss carryforwards 390,430 358,291
Tax credit carryforwards 111,117 113,856
Other items 29,261 29,820
--------------------------------------------------------------------------
Total deferred tax assets 654,427 635,649
Valuation allowance (281,529) (262,389)
--------------------------------------------------------------------------
Net deferred tax assets 372,898 373,260
--------------------------------------------------------------------------
Net deferred tax liabilities $ 476,040 $ 405,335
==========================================================================
</TABLE>
The difference between the Corporation's effective income tax rate and the
United States statutory rate is reconciled below:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------
1994 1993 1992
-----------------------------------------------------------------------
<S> <C> <C> <C>
United States statutory rate 35.0% (35.0)% 34.0%
Effect of foreign operations,
including foreign tax credits 33.4 71.6 97.4
State income taxes, net of Federal
income tax benefit .5 .5 1.0
Alternative minimum tax (1.8) (2.9) (25.5)
Tax credits -- (2.6) (2.1)
Refund of prior years' income
taxes and related adjustments -- -- (9.1)
Other items 1.6 1.6 (1.8)
-----------------------------------------------------------------------
Total 68.7% 33.2% 93.9%
=======================================================================
</TABLE>
35
<PAGE> 30
The Corporation has not recorded deferred income taxes applicable to
undistributed earnings of foreign subsidiaries that are indefinitely reinvested
in foreign operations. Undistributed earnings amounted to approximately $950
million at December 31, 1994, excluding amounts which, if remitted, generally
would not result in any additional U.S. income taxes because of available
foreign tax credits. If the earnings of such foreign subsidiaries were not
indefinitely reinvested, a deferred tax liability of approximately $175 million
would have been required.
For income tax reporting at December 31, 1994, the Corporation has general
business credit carryforwards of approximately $20 million, expiring in 1999
through 2001. In addition, the Corporation has alternative minimum tax credit
carryforwards of approximately $80 million, which can be carried forward
indefinitely. The Corporation also has net operating loss carryforwards of
approximately $120 million in the United States, expiring in 2009 and
approximately $700 million relating to a refining subsidiary, expiring through
2009.
Income taxes paid (net of refunds) in 1994, 1993 and 1992 amounted to
$66,569,000, $117,849,000 and $48,091,000, respectively.
11. NET INCOME PER SHARE
Net income per share was computed on the weighted average number of shares of
common stock and common stock equivalents outstanding during each year
(92,968,993 shares in 1994, 92,594,871 shares in 1993 and 87,316,950 shares in
1992). Such fully diluted weighted average number of shares reflected the
exercise of outstanding stock options.
12. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Corporation produces, purchases, transports and sells crude oil and natural
gas and manufactures, purchases, transports and markets refined products. The
Corporation also maintains inventories of crude oil and refined products. The
Corporation uses futures, forward, option and swap contracts to reduce the
effects of fluctuations in crude oil, natural gas and refined product prices. In
addition, a significant portion of the Corporation's long-term borrowings have
floating interest rates. The Corporation also has exploration and production
activities in foreign countries. Therefore, it is affected by changes in
interest rates and foreign currency exchange rates. Interest rate conversion
agreements and foreign currency exchange contracts protect the Corporation from
fluctuations in interest and exchange rates.
Commodity hedging: The Corporation uses futures, forward and option contracts to
reduce the effects of fluctuations in the prices of crude oil, natural gas and
refined products. These contracts permit settlement by delivery of commodities
and, therefore, are not financial instruments, as defined. The Corporation uses
these contracts and financial instruments such as over-the-counter option and
swap contracts in its commodity hedging activities. At December 31, 1994, the
Corporation's hedging activities included commodity and financial instrument
contracts, maturing through 1995, covering 56,000,000 barrels of crude oil and
refined products and 195,000,000 Mcf of natural gas. Of the crude oil and
refined product hedges, 26,500,000 barrels relate to exploration and production
activities and the remaining
36
<PAGE> 31
29,500,000 barrels relate to refining and marketing operations. At December 31,
1993, contracts covering 62,000,000 barrels of crude oil and refined products
and 137,000,000 Mcf of natural gas, which matured in 1994, were used as hedges.
The Corporation produced 91,000,000 barrels of crude oil (including natural gas
liquids) and 309,000,000 Mcf of natural gas in 1994 and had approximately
40,000,000 barrels of crude oil and refined products in its refining and
marketing inventories at December 31, 1994. Since the contracts described above
qualify as hedges and correlate to price movements of crude oil, natural gas and
refined products, any gains or losses resulting from market changes will be
offset by losses or gains on the Corporation's hedged inventory or production.
Total unrealized gains for the Corporation's petroleum and natural gas hedging
activities were approximately $20,000,000 at December 31, 1994 ($126,000,000 at
December 31, 1993). Deferred gains related to anticipated transactions are not
material.
Financial instruments: At December 31, 1994, the Corporation has $225,000,000 of
notional value interest rate conversion agreements with a weighted average
maturity of approximately one year ($444,500,000 at December 31, 1993),
$155,000,000 of notional value foreign currency forward and purchased option
contracts maturing in 1995 ($35,000,000 at December 31, 1993) and $117,000,000
in letters of credit outstanding ($89,000,000 at December 31, 1993). 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.
Fair value disclosure: The Corporation values financial instruments as required
by FAS No. 107, Disclosures about Fair Values of Financial Instruments. The
carrying amounts of cash and cash equivalents, short-term debt and long-term,
variable-rate debt approximate fair value. The Corporation estimates the fair
value of its long-term, fixed-rate debt generally using discounted cash flow
analysis based on the Corporation's current borrowing rates for debt with
similar maturities. Interest rate conversion agreements and foreign currency
exchange contracts are valued based on current termination values or quoted
market prices of comparable contracts. The Corporation's valuation of commodity
contracts considers quoted market prices, time value, volatility of the
underlying commodities and other factors.
The carrying amounts of the Corporation's financial instruments and commodity
contracts, including those used in the Corporation's hedging activities,
generally approximate their fair values at December 31, except as follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------
1994 1993
-------------------- --------------------
Balance Balance
Millions of dollars, Sheet Fair Sheet Fair
asset (liability) Amount Value Amount Value
----------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Long-term, fixed-rate debt $(1,548) $(1,519) $(1,321) $(1,446)
Commodity contracts,
including financial
instruments 7* 20 75* 126
Interest rate conversion
agreements -- (2) -- (19)
Foreign currency exchange
agreements and options -- (2) -- (3)
==================================================================================
</TABLE>
*Represents margin accounts on futures contracts.
37
<PAGE> 32
At times, the Corporation uses oil and gas futures, forward, option and swap
contracts that are not related to the hedging program discussed above. This
activity and its results are not material.
The Corporation's financial instruments with off-balance-sheet risks are with
major financial institutions and, along with cash and cash equivalents and
accounts receivable, expose the Corporation to market and credit risks and may
at times be concentrated with certain counterparties or groups of
counterparties. The credit worthiness of counterparties is subject to continuing
review and full performance is anticipated.
13. LEASED ASSETS
The Corporation and certain of its subsidiaries lease tankers, gasoline
stations, office space and other assets for varying periods. Leases that expire
generally are expected to be renewed or replaced by other leases. Certain leases
are classified as capital leases in accordance with the provisions of FAS No.
13. At December 31, 1994, net capital lease assets of $95,239,000, representing
natural gas production and transportation facilities in the United Kingdom, are
included in property, plant and equipment in the Consolidated Balance Sheet.
At December 31, 1994, future minimum rental payments applicable to capital and
noncancelable operating leases (other than oil and gas leases) are as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------
Operating Capital
Thousands of dollars Leases Leases
--------------------------------------------------------------
<S> <C> <C>
1995 $115,882 $ 19,439
1996 103,501 20,566
1997 90,652 21,663
1998 67,960 22,844
1999 55,282 26,067
Remaining years 447,704 --
--------------------------------------------------------------
Total minimum lease payments 880,981 110,579
Less: Imputed interest -- 15,519
Income from subleases 20,655 --
--------------------------------------------------------------
Net minimum lease payments $860,326 $ 95,060
--------------------------------------------------------------
Capitalized lease obligations--
Current $ 14,132
Long-term 80,928
--------------------------------------------------------------
Total $ 95,060
==============================================================
</TABLE>
Rental expense for all operating leases, other than rentals applicable to oil
and gas leases, was as follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------
Thousands of dollars 1994 1993 1992
----------------------------------------------------------------------
<S> <C> <C> <C>
Total rental expense $164,395 $180,459 $164,170
Less income from subleases 3,443 855 1,431
----------------------------------------------------------------------
Net rental expense $160,952 $179,604 $162,739
======================================================================
</TABLE>
14. INFORMATION ON MAJOR OPERATING ACTIVITIES
The Corporation operates principally in the petroleum industry. Exploration and
production operations include the exploration for, and production and processing
of, crude oil and natural gas. Refining and marketing operations include the
manufacture, purchase, transportation and marketing of refined products.
Financial data by major geographic area for each of the three years ended
December 31, 1994 follow:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------
United Consol-
Millions of dollars States(a) Europe Other idated(b)
---------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1994
Operating revenues
Unaffiliated customers $5,437 $ 907 $258 $6,602
Intergeographic transfers -- 247 77
Operating profit 66 303 112 481
Identifiable assets 5,293 2,316 729 8,338
---------------------------------------------------------------------------
1993
Operating revenues
Unaffiliated customers $4,743 $ 929 $208 $5,880
Intergeographic transfers -- -- 147
Operating profit (loss) (330) 147 116 (67)
Identifiable assets 5,401 2,412 829 8,642
---------------------------------------------------------------------------
1992
Operating revenues
Unaffiliated customers $4,686 $ 978 $194 $5,858
Intergeographic transfers -- 1 152
Operating profit (loss) (38) 236 73 271
Identifiable assets 5,350 2,459 913 8,722
===========================================================================
</TABLE>
(a) Includes U.S. Virgin Islands and shipping operations.
(b) After elimination of transactions between affiliates, which are valued at
approximate market prices.
38
<PAGE> 33
Financial data by major operating activity for each of the three years ended
December 31, 1994 follow:
<TABLE>
<CAPTION>
Exploration and Refining and Corporate
Millions of dollars Production Marketing and Other Consolidated(a)
-------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1994
Operating revenues
Total operating revenues $2,665 $4,205 $ 527
Less: Transfers between affiliates 402 51 342
-------------------------------------------------------------------------------------------------------------------
Operating revenues from unaffiliated customers $2,263 $4,154 $ 185 $6,602
-------------------------------------------------------------------------------------------------------------------
Operating profit $ 368 $ 83 $ 30 $ 481
Interest expense -- -- (245) (245)
(Provision) benefit for income taxes (211) 12 37 (162)
-------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 157 $ 95 $(178) $ 74
-------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization $ 698 $ 150 $ 32 $ 880
Identifiable assets 4,117 3,617 604 8,338
Capital expenditures 531 62 3 596
-------------------------------------------------------------------------------------------------------------------
1993
Operating revenues
Total operating revenues $2,541 $3,540 $ 578
Less: Transfers between affiliates 248 59 472
-------------------------------------------------------------------------------------------------------------------
Operating revenues from unaffiliated customers $2,293 $3,481 $ 106 $5,880
-------------------------------------------------------------------------------------------------------------------
Operating profit (loss) $ 260 $ (318) $ (9) $ (67)
Interest expense -- -- (156) (156)
(Provision) benefit for income taxes (144) 25 74 (b) (45)
-------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 116 $ (293) $ (91) $ (268)
-------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization $ 639 $ 101 $ 29 $ 769
Identifiable assets 4,446 3,576 620 8,642
Capital expenditures 755 591 2 1,348
-------------------------------------------------------------------------------------------------------------------
1992
Operating revenues
Total operating revenues $2,399 $3,722 $ 617
Less: Transfers between affiliates 281 107 492
-------------------------------------------------------------------------------------------------------------------
Operating revenues from unaffiliated customers $2,118 $3,615 $ 125 $5,858
-------------------------------------------------------------------------------------------------------------------
Operating profit (loss) $ 373 $ (121) $ 19 $ 271
Interest expense -- -- (147) (147)
(Provision) benefit for income taxes (154) (8) 46 (116)
-------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 219 $ (129) $ (82) $ 8
-------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization $ 677 $ 66 $ 31 $ 774
Identifiable assets 4,703 3,397 622 8,722
Capital expenditures 916 639 3 1,558
===================================================================================================================
</TABLE>
(a) After elimination of transactions between affiliates, which are valued at
approximate market prices.
(b) Includes a benefit of $29 million from the cumulative effect of the change
in accounting for income taxes required by FAS No. 109.
39
<PAGE> 34
REPORT OF MANAGEMENT
Amerada Hess Corporation and Consolidated Subsidiaries
The consolidated financial statements of Amerada Hess Corporation and
consolidated subsidiaries were prepared by and are the responsibility of
management. These financial statements conform with generally accepted
accounting principles and are, in part, based on estimates and judgements of
management. Other information included in this Annual Report is consistent with
that in the consolidated financial statements.
The Corporation maintains a system of internal controls designed to provide
reasonable assurance that assets are safeguarded and that transactions are
properly executed and recorded. Judgements are required to balance the relative
costs and benefits of this system of internal controls.
The Corporation's consolidated financial statements have been audited by
Ernst & Young LLP, independent auditors, who have been selected by the Audit
Committee of the Board of Directors and approved by the stockholders. Ernst &
Young LLP assesses the Corporation's system of internal controls and performs
tests and procedures that they consider necessary to arrive at an opinion on the
fairness of the consolidated financial statements.
The Audit Committee of the Board of Directors, which consists solely of
nonemployee directors, meets periodically with the independent auditors,
internal auditors and management to review and discuss the Corporation's
financial information, the system of internal controls and the results of
internal and external audits. Ernst & Young LLP and the Corporation's internal
auditors have unrestricted access to the Audit Committee to discuss audit
findings and other financial matters.
/s/ Leon Hess
Leon Hess
Chairman of the Board and
Chief Executive Officer
/s/ John Y. Schreyer
John Y. Schreyer
Executive Vice President and
Chief Financial Officer
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Amerada Hess Corporation
We have audited the accompanying consolidated balance sheet of Amerada Hess
Corporation and consolidated subsidiaries as of December 31, 1994 and 1993 and
the related consolidated statements of income, retained earnings, changes in
common stock and capital in excess of par value and cash flows for each of the
three years in the period ended December 31, 1994. These financial statements
are the responsibility of the Corporation's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 Amerada Hess
Corporation and consolidated subsidiaries at December 31, 1994 and 1993 and the
consolidated results of their operations and their consolidated cash flows for
each of the three years in the period ended December 31, 1994, in conformity
with generally accepted accounting principles.
/s/ Ernst & Young LLP
New York, NY
February 15, 1995
40
<PAGE> 35
SUPPLEMENTARY OIL AND GAS DATA
Amerada Hess Corporation and Consolidated Subsidiaries
The supplementary oil and gas data that follows is presented in accordance with
Statement of Financial Accounting Standards (FAS) No. 69, 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.
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
United Other
For the Years Ended December 31 (Millions of dollars) Total States Canada Europe Areas
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1994
Property acquisitions $ 21 $ 14 $ 5 $ -- $ 2
Exploration 274 139 31 99 5
Development 333 120 31 170 12
1993
Property acquisitions $ 56 $ 48 $ 5 $ 2 $ 1
Exploration 274 147 27 98 2
Development 527 151 22 345 9
1992
Property acquisitions $ 38 $ 31 $ 2 $ -- $ 5
Exploration 229 104 17 89 19
Development 742 116 10 608 8
---------------------------------------------------------------------------------------------------
</TABLE>
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
At December 31 (Millions of dollars) 1994 1993
-------------------------------------------------------------------------------------------------------
<S> <C> <C>
Unproved properties $ 439 $ 484
Proved properties 2,071 2,057
Wells, equipment and related facilities 7,147 6,687
-------------------------------------------------------------------------------------------------------
Total costs 9,657 9,228
Less: Reserves for depreciation, depletion, amortization and lease impairment 5,988 5,266
-------------------------------------------------------------------------------------------------------
Net capitalized costs $3,669 $3,962
=======================================================================================================
</TABLE>
41
<PAGE> 36
The results of operations for oil and gas producing activities shown below
exclude sales of purchased crude oil and natural gas, non-operating revenues
(which include the gain on the sale of an undeveloped natural gas field in
1994), interest expense and gains and losses resulting from foreign currency
exchange transactions. Therefore, these results differ from the net income from
exploration and production operations in Note 14 to the financial statements.
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
United Other
For the Years Ended December 31 (Millions of dollars) Total States Canada Europe Areas
---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1994
Sales and other operating revenues
Unaffiliated customers $1,687 $576 $172 $ 879 $ 60
Inter-company 385 98 2 237 48
---------------------------------------------------------------------------------------------------------------
Total revenues 2,072 674 174 1,116 108
---------------------------------------------------------------------------------------------------------------
Costs and expenses
Production expenses, including related taxes 593 210 47 318 18
Exploration expenses, including dry holes 250 128 18 99 5
Other operating expenses 187 70 11 92 14
Depreciation, depletion, amortization and lease impairment 746 293 57 368 28
Provision for income taxes 197 (10) 22 167 18
---------------------------------------------------------------------------------------------------------------
Total costs and expenses 1,973 691 155 1,044 83
---------------------------------------------------------------------------------------------------------------
Results of operations $ 99 $(17) $ 19 $ 72 $ 25
---------------------------------------------------------------------------------------------------------------
1993
Sales and other operating revenues
Unaffiliated customers $1,790 $704 $176 $ 890 $ 20
Inter-company 227 119 -- -- 108
---------------------------------------------------------------------------------------------------------------
Total revenues 2,017 823 176 890 128
---------------------------------------------------------------------------------------------------------------
Costs and expenses
Production expenses, including related taxes 607 233 49 294 31
Exploration expenses, including dry holes 259 150 18 89 2
Other operating expenses 218 79 12 109 18
Depreciation, depletion, amortization and lease impairment 694 332 54 271 37
Provision for income taxes 133 9 23 82 19
---------------------------------------------------------------------------------------------------------------
Total costs and expenses 1,911 803 156 845 107
---------------------------------------------------------------------------------------------------------------
Results of operations $ 106 $ 20 $ 20 $ 45 $ 21
---------------------------------------------------------------------------------------------------------------
1992
Sales and other operating revenues
Unaffiliated customers $1,846 $701 $161 $ 963 $ 21
Inter-company 257 141 -- 2 114
---------------------------------------------------------------------------------------------------------------
Total revenues 2,103 842 161 965 135
---------------------------------------------------------------------------------------------------------------
Costs and expenses
Production expenses, including related taxes 603 223 48 310 22
Exploration expenses, including dry holes 229 100 14 95 20
Other operating expenses 230 55 14 137 24
Depreciation, depletion, amortization and lease impairment 736 398 61 241 36
Provision for income taxes 122 12 17 59 34
---------------------------------------------------------------------------------------------------------------
Total costs and expenses 1,920 788 154 842 136
---------------------------------------------------------------------------------------------------------------
Results of operations $ 183 $ 54 $ 7 $ 123 $ (1)
===============================================================================================================
</TABLE>
42
<PAGE> 37
The Corporation's net oil and gas reserves have been estimated by DeGolyer and
MacNaughton, independent consultants. The reserves in the tabulation below
include proved undeveloped crude oil and natural gas reserves that will require
substantial future development expenditures. The estimates of the Corporation's
proved reserves of crude oil and natural gas (after deducting royalties and
operating interests owned by others) follow:
OIL AND GAS RESERVES
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
United Other
Total States Canada Europe Areas
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Net Proved Developed and Undeveloped Reserves
Crude Oil, Including Condensate and Natural Gas
Liquids (Millions of barrels)
At January 1, 1992 638 201 44 349 44
Revisions of previous estimates 58 25 -- 32 1
Extensions, discoveries and other additions 37 4 1 32 --
Purchases of minerals in-place 1 -- -- 1 --
Production (82) (27) (5) (43) (7)
--------------------------------------------------------------------------------------------------
At December 31, 1992 652 203 40 371 38
Revisions of previous estimates 66 16 -- 43 7
Extensions, discoveries and other additions 28 5 3 20 --
Purchases of minerals in-place 3 -- 1 2 --
Production (79) (26) (5) (41) (7)
--------------------------------------------------------------------------------------------------
At December 31, 1993 670 198 39 395 38
Revisions of previous estimates 49 13 (2) 35 3
Extensions, discoveries and other additions 12 8 2 2 --
Purchases of minerals in-place 8 4 -- -- 4
Sales of minerals in-place (3) -- -- (3) --
Production (92) (25) (5) (56) (6)
--------------------------------------------------------------------------------------------------
At December 31, 1994 644 198 34 373 39
--------------------------------------------------------------------------------------------------
Natural Gas (Millions of Mcf)
At January 1, 1992 2,551 1,058 558 935 --
Revisions of previous estimates 166 90 74 2 --
Extensions, discoveries and other additions 224 70 16 138 --
Purchases of minerals in-place 38 11 -- 27 --
Production (339) (220) (51) (68) --
--------------------------------------------------------------------------------------------------
At December 31, 1992 2,640 1,009 597 1,034 --
Revisions of previous estimates 127 30 (5) 102 --
Extensions, discoveries and other additions 189 82 65 42 --
Purchases of minerals in-place 20 11 4 5 --
Production (323) (183) (61) (79) --
--------------------------------------------------------------------------------------------------
At December 31, 1993 2,653 949 600 1,104 --
Revisions of previous estimates 142 105 (1) 38 --
Extensions, discoveries and other additions 167 101 50 16 --
Purchases of minerals in-place 4 3 -- 1 --
Sales of minerals in-place (76) -- -- (76) --
Production (309) (156) (68) (85) --
--------------------------------------------------------------------------------------------------
At December 31, 1994 2,581 1,002* 581 998 --
--------------------------------------------------------------------------------------------------
Net Proved Developed Reserves
Crude Oil, Including Condensate and Natural Gas
Liquids (Millions of barrels)
At January 1, 1992 443 172 43 186 42
At December 31, 1992 436 173 40 191 32
At December 31, 1993 514 169 38 271 36
At December 31, 1994 505 171 33 263 38
Natural Gas (Millions of Mcf)
At January 1, 1992 1,872 915 529 428 --
At December 31, 1992 2,002 851 576 575 --
At December 31, 1993 2,260 794 579 887 --
At December 31, 1994 2,210 838 558 814 --
==================================================================================================
</TABLE>
*Excludes 486 million Mcf of carbon dioxide gas for sale or use in company
operations.
43
<PAGE> 38
The standardized measure of discounted future net cash flows relating to proved
oil and gas reserves required to be disclosed by FAS No. 69 is based on
assumptions and judgements. As a result, the future net cash flow estimates are
highly subjective and could be materially different if other assumptions were
used. Therefore, caution should be exercised in the use of the data presented
below.
Future net cash flows are calculated by applying year-end oil and gas selling
prices (adjusted for price changes provided by contractual arrangements,
including hedges) to estimated future production of proved oil and gas reserves,
less estimated future development and production costs and future income tax
expenses. Future net cash flows are discounted at the prescribed rate of 10%. No
recognition is given in the discounted future net cash flow estimates to
depreciation, depletion, amortization and lease impairment, exploration
expenses, interest expense, general and administrative expenses and changes in
future prices and costs. The selling prices of crude oil and natural gas are
highly volatile.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
United Other
At December 31 (Millions of dollars) Total States Canada Europe Areas
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1994
Future revenues $14,545 $4,267 $1,266 $8,236 $776
-----------------------------------------------------------------------------------------------------
Less:
Future development and production costs 6,874 2,317 667 3,696 194
Future income tax expenses 2,789 465 152 1,910 262
-----------------------------------------------------------------------------------------------------
9,663 2,782 819 5,606 456
-----------------------------------------------------------------------------------------------------
Future net cash flows 4,882 1,485 447 2,630 320
Less: Discount at 10% annual rate 1,622 577 168 787 90
-----------------------------------------------------------------------------------------------------
Standardized measure of discounted future net
cash flows $ 3,260 $ 908 $ 279 $1,843 $230
-----------------------------------------------------------------------------------------------------
1993
Future revenues $13,484 $4,135 $1,714 $7,059 $576
-----------------------------------------------------------------------------------------------------
Less:
Future development and production costs 6,505 2,258 704 3,360 183
Future income tax expenses 2,235 407 308 1,380 140
-----------------------------------------------------------------------------------------------------
8,740 2,665 1,012 4,740 323
-----------------------------------------------------------------------------------------------------
Future net cash flows 4,744 1,470 702 2,319 253
Less: Discount at 10% annual rate 1,705 556 266 797 86
-----------------------------------------------------------------------------------------------------
Standardized measure of discounted future net
cash flows $ 3,039 $ 914 $ 436 $1,522 $167
-----------------------------------------------------------------------------------------------------
1992
Future revenues $15,802 $5,035 $1,497 $8,475 $795
-----------------------------------------------------------------------------------------------------
Less:
Future development and production costs 6,870 2,505 604 3,570 191
Future income tax expenses 3,330 606 320 2,235 169
-----------------------------------------------------------------------------------------------------
10,200 3,111 924 5,805 360
-----------------------------------------------------------------------------------------------------
Future net cash flows 5,602 1,924 573 2,670 435
Less: Discount at 10% annual rate 2,106 777 213 949 167
-----------------------------------------------------------------------------------------------------
Standardized measure of discounted future net
cash flows $ 3,496 $1,147 $ 360 $1,721 $268
=====================================================================================================
</TABLE>
44
<PAGE> 39
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
For the years ended December 31 (Millions of dollars) 1994 1993 1992
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows at beginning of year $ 3,039 $ 3,496 $ 3,401
--------------------------------------------------------------------------------------------------------------------
Changes during the year
Sales and transfers of oil and gas produced during year, net of
production costs (1,479) (1,410) (1,500)
Development costs incurred during year 333 527 742
Net changes in prices and production costs applicable to future production 604 (1,569) 62
Net change in estimated future development costs (264) (68) (13)
Extensions and discoveries (including improved recovery) of oil and
gas reserves, less related costs 135 167 284
Revisions of previous oil and gas reserve estimates 314 288 623
Purchases (sales) of minerals in-place (2) 23 35
Accretion of discount 437 539 475
Net change in income taxes (380) 547 (513)
Revision in rate or timing of future production and other changes 523 499 (100)
--------------------------------------------------------------------------------------------------------------------
Total 221 (457) 95
--------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows at end of year $ 3,260 $ 3,039 $ 3,496
====================================================================================================================
</TABLE>
45
<PAGE> 40
TEN-YEAR SUMMARY OF FINANCIAL DATA
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
Thousands of dollars, except per share data 1994 1993 1992
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
STATEMENT OF CONSOLIDATED INCOME
Revenues
Sales (excluding excise taxes) and other operating revenues
Crude oil (including sales of purchased oil) $1,228,045 $1,219,750 $1,362,118
Natural gas (including sales of purchased gas) 1,063,560 1,020,563 787,996
Petroleum products 3,980,563 3,348,900 3,428,702
Other operating revenues 329,816 290,308 279,541
--------------------------------------------------------------------------------------------------------------
Total 6,601,984 5,879,521 5,858,357
Non-operating revenues 96,809 21,153 95,352
--------------------------------------------------------------------------------------------------------------
Total revenues 6,698,793 5,900,674 5,953,709
--------------------------------------------------------------------------------------------------------------
Costs and expenses
Cost of products sold and operating expenses 4,449,819 4,287,139 4,039,180
Exploration expenses, including dry holes 249,433 258,826 228,998
Selling, general and administrative expenses 590,647 596,919 581,542
Interest expense 245,149 156,615 147,099
Depreciation, depletion and amortization 879,679 769,390 773,507
Lease impairment 48,254 55,261 59,898
Special charge for marine transportation costs -- -- --
Provision for income taxes 162,098 44,727(*) 115,940
--------------------------------------------------------------------------------------------------------------
Total costs and expenses 6,625,079 6,168,877 5,946,164
--------------------------------------------------------------------------------------------------------------
Net income (loss) $ 73,714 $ (268,203) $ 7,545
--------------------------------------------------------------------------------------------------------------
Net income (loss) per share (**) $ .79 $ (2.90) $ .09
--------------------------------------------------------------------------------------------------------------
DIVIDENDS PER SHARE
Common stock $ .60 $ .60 $ .60
Preferred stock (redeemed in 1987) -- -- --
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING
(in thousands) 92,969 92,595 87,317
==============================================================================================================
</TABLE>
*Includes a benefit of $29,459 ($.32 per share) from the cumulative effect of
the change in accounting for income taxes required by FAS No. 109.
**For a description of the basis of computing earnings per share, see Note 11 to
consolidated financial statements.
46
<PAGE> 41
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
Thousands of dollars, except per share data 1991 1990 1989 1988
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
STATEMENT OF CONSOLIDATED INCOME
Revenues
Sales (excluding excise taxes) and other operating revenues
Crude oil (including sales of purchased oil) $1,448,793 $1,248,193 $ 904,233 $ 872,757
Natural gas (including sales of purchased gas) 574,004 458,615 315,578 288,915
Petroleum products 3,897,748 4,587,646 4,107,770 2,864,342
Other operating revenues 346,300 653,051 261,373 179,997
-----------------------------------------------------------------------------------------------------------------------------
Total 6,266,845 6,947,505 5,588,954 4,206,011
Non-operating revenues 149,496 133,593 90,373 57,533
-----------------------------------------------------------------------------------------------------------------------------
Total revenues 6,416,341 7,081,098 5,679,327 4,263,544
-----------------------------------------------------------------------------------------------------------------------------
Costs and expenses
Cost of products sold and operating expenses 4,409,832 4,708,925 3,837,800 2,964,534
Exploration expenses, including dry holes 301,183 276,200 164,925 182,205
Selling, general and administrative expenses 582,549 512,805 422,491 380,169
Interest expense 177,850 224,200 187,811 145,439
Depreciation, depletion and amortization 765,877 687,064 492,510 373,661
Lease impairment 62,888 56,403 53,424 67,753
Special charge for marine transportation costs -- -- -- --
Provision for income taxes 31,854 132,788 44,017 25,566
-----------------------------------------------------------------------------------------------------------------------------
Total costs and expenses 6,332,033 6,598,385 5,202,978 4,139,327
-----------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 84,308 $ 482,713 $ 476,349 $ 124,217
-----------------------------------------------------------------------------------------------------------------------------
Net income (loss) per share (**) $ 1.04 $ 5.96 $ 5.87 $ 1.51
-----------------------------------------------------------------------------------------------------------------------------
DIVIDENDS PER SHARE
Common stock $ .60 $ .60 $ .60 $ .60
Preferred stock (redeemed in 1987) -- -- -- --
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING
(in thousands) 81,088 81,023 81,147 82,031
=============================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
Thousands of dollars, except per share data 1987 1986 1985
---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
STATEMENT OF CONSOLIDATED INCOME
Revenues
Sales (excluding excise taxes) and other operating revenues
Crude oil (including sales of purchased oil) $ 886,504 $ 806,927 $2,150,919
Natural gas (including sales of purchased gas) 284,610 284,533 336,552
Petroleum products 3,347,242 2,649,197 4,877,005
Other operating revenues 195,209 270,525 307,776
---------------------------------------------------------------------------------------------------------------
Total 4,713,565 4,011,182 7,672,252
Non-operating revenues 71,024 51,073 50,290
---------------------------------------------------------------------------------------------------------------
Total revenues 4,784,589 4,062,255 7,722,542
---------------------------------------------------------------------------------------------------------------
Costs and expenses
Cost of products sold and operating expenses 3,521,552 3,155,868 5,829,095
Exploration expenses, including dry holes 106,440 148,506 229,753
Selling, general and administrative expenses 328,118 315,199 300,542
Interest expense 144,147 164,275 189,263
Depreciation, depletion and amortization 359,825 382,273 373,734
Lease impairment 71,657 85,971 110,297
Special charge for marine transportation costs -- -- 536,692
Provision for income taxes 22,990 (7,267) 375,277
---------------------------------------------------------------------------------------------------------------
Total costs and expenses 4,554,729 4,244,825 7,944,653
---------------------------------------------------------------------------------------------------------------
Net income (loss) $ 229,860 $ (182,570) $ (222,111)
---------------------------------------------------------------------------------------------------------------
Net income (loss) per share (**) $ 2.73 $ (2.16) $ (2.63)
---------------------------------------------------------------------------------------------------------------
Dividends Per Share
Common stock $ .45 -- $ 1.10
Preferred stock (redeemed in 1987) $ 2.63 $ 3.50 $ 3.50
Weighted Average Number of Shares Outstanding
(in thousands) 84,136 84,440 84,536
===============================================================================================================
</TABLE>
47
<PAGE> 42
TEN-YEAR SUMMARY OF FINANCIAL DATA
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Thousands of dollars, except per share data 1994 1993 1992
-----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
SELECTED BALANCE SHEET DATA AT YEAR-END
Cash and cash equivalents $ 53,135 $ 79,635 $ 141,014
Working capital 520,247 245,026 551,459
Property, plant and equipment
Exploration and production $ 9,656,923 $ 9,227,937 $ 9,071,396
Refining and marketing 3,892,724 3,834,674 3,294,958
Transportation and other 755,179 724,629 724,411
-----------------------------------------------------------------------------------------------------------
Total--at cost 14,304,826 13,787,240 13,090,765
Less reserves 7,938,824 7,052,328 6,646,801
-----------------------------------------------------------------------------------------------------------
Property, plant and equipment--net $ 6,366,002 $ 6,734,912 $ 6,443,964
-----------------------------------------------------------------------------------------------------------
Total assets $ 8,337,940 $ 8,641,546 $ 8,721,756
Total debt 3,339,788 3,687,922 3,186,199
Stockholders' equity 3,099,629 3,028,911 3,387,599
Stockholders' equity per share $ 33.33 $ 32.71 $ 36.59
-----------------------------------------------------------------------------------------------------------
SUMMARIZED STATEMENT OF CASH FLOWS
Net cash provided by operating activities $ 957,018 $ 819,423 $ 1,137,707
-----------------------------------------------------------------------------------------------------------
Cash flows from investing activities
Capital expenditures
Exploration and production (531,409) (754,876) (915,476)
Refining and marketing (62,238) (591,545) (639,365)
Transportation and other (2,637) (1,620) (2,953)
-----------------------------------------------------------------------------------------------------------
Total capital expenditures (596,284) (1,348,041) (1,557,794)
Other, including proceeds from sales of
property, plant and equipment 72,804 12,436 25,423
-----------------------------------------------------------------------------------------------------------
Net cash used in investing activities (523,480) (1,335,605) (1,532,371)
-----------------------------------------------------------------------------------------------------------
Cash flows from financing activities
Issuance (repayment) of notes (54,153) 117,791 (159,756)
Long-term borrowings 289,843 547,704 675,016
Repayment of long-term debt and
capitalized lease obligations (642,112) (167,769) (524,384)
Issuance of common stock -- -- 497,360
Cash dividends paid (55,711) (41,603) (64,194)
Common and preferred stock retired -- -- --
-----------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (462,133) 456,123 424,042
-----------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash 2,095 (1,320) (8,534)
-----------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents $ (26,500) $ (61,379) $ 20,844
-----------------------------------------------------------------------------------------------------------
STOCKHOLDER DATA AT YEAR-END
Number of common shares outstanding (in thousands)* 92,996 92,587 92,584
Number of stockholders (based on number of
holders of record) 11,506 12,000 13,088
Market price of common stock $ 45.63 $ 45.13 $ 46.00
==============================================================================================================
</TABLE>
*Assuming conversion of preferred prior to 1987.
48
<PAGE> 43
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
Thousands of dollars, except per share data 1991 1990 1989 1988
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
SELECTED BALANCE SHEET DATA AT YEAR-END
Cash and cash equivalents $ 120,170 $ 129,914 $ 120,300 $ 213,184
Working capital 625,370 603,244 493,168 285,074
Property, plant and equipment
Exploration and production $ 9,174,705 $ 8,210,531 $ 6,403,799 $5,360,817
Refining and marketing 2,632,026 2,230,000 2,053,018 1,973,782
Transportation and other 723,101 717,452 710,439 703,862
-----------------------------------------------------------------------------------------------------------------------------
Total--at cost 12,529,832 11,157,983 9,167,256 8,038,461
Less reserves 6,339,232 5,594,399 4,688,142 4,358,765
-----------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment--net $ 6,190,600 $ 5,563,584 $ 4,479,114 $3,679,696
-----------------------------------------------------------------------------------------------------------------------------
Total assets $ 8,841,435 $ 9,056,636 $ 6,867,411 $5,371,979
Total debt 3,266,195 2,925,285 2,697,184 1,672,329
Stockholders' equity 3,131,982 3,106,029 2,560,628 2,215,154
Stockholders' equity per share $ 38.63 $ 38.34 $ 31.69 $ 27.02
-----------------------------------------------------------------------------------------------------------------------------
SUMMARIZED STATEMENT OF CASH FLOWS
Net cash provided by operating activities $ 1,364,268 $ 1,326,444 $ 805,848 $ 747,393
-----------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities
Capital expenditures
Exploration and production (1,292,935) (1,265,168) (1,729,357) (652,600)
Refining and marketing (410,645) (182,090) (86,645) (60,084)
Transportation and other (8,735) (14,169) (12,667) (17,245)
-----------------------------------------------------------------------------------------------------------------------------
Total capital expenditures (1,712,315) (1,461,427) (1,828,669) (729,929)
Other, including proceeds from sales of
property, plant and equipment 37,788 (12,012) 6,644 16,401
-----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (1,674,527) (1,473,439) (1,822,025) (713,528)
-----------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities
Issuance (repayment) of notes (183,351) 46,744 13,823 (205,414)
Long-term borrowings 786,280 461,413 1,203,994 416,161
Repayment of long-term debt and
capitalized lease obligations (269,414) (287,531) (194,870) (191,159)
Issuance of common stock -- -- -- --
Cash dividends paid (36,468) (60,681) (48,785) (49,248)
Common and preferred stock retired -- (6,213) (43,632) (7,420)
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 297,047 153,732 930,530 (37,080)
-----------------------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash 3,468 2,877 (7,237) (10,114)
-----------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents $ (9,744) $ 9,614 $ (92,884) $ (13,329)
-----------------------------------------------------------------------------------------------------------------------------
STOCKHOLDER DATA AT YEAR-END
Number of common shares outstanding (in thousands)* 81,068 81,019 80,804 81,979
Number of stockholders (based on number of
holders of record) 13,732 14,669 16,638 18,031
Market price of common stock $ 47.50 $ 46.38 $ 48.75 $ 31.50
=============================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
Thousands of dollars, except per share data 1987 1986 1985
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
SELECTED BALANCE SHEET DATA AT YEAR-END
Cash and cash equivalents $ 226,513 $ 92,681 $ 171,074
Working capital 161,764 231,602 434,049
Property, plant and equipment
Exploration and production $5,010,724 $4,508,499 $4,468,310
Refining and marketing 1,922,620 1,900,919 1,901,371
Transportation and other 680,257 721,743 789,781
------------------------------------------------------------------------------------------------------------
Total--at cost 7,613,601 7,131,161 7,159,462
Less reserves 4,064,227 3,601,978 3,220,824
------------------------------------------------------------------------------------------------------------
Property, plant and equipment--net $3,549,374 $3,529,183 $3,938,638
------------------------------------------------------------------------------------------------------------
Total assets $5,304,808 $4,904,710 $6,213,662
Total debt 1,631,345 1,528,367 1,935,967
Stockholders' equity 2,158,544 1,938,793 2,114,757
Stockholders' equity per share $ 26.30 $ 22.97 $ 25.04
------------------------------------------------------------------------------------------------------------
SUMMARIZED STATEMENT OF CASH FLOWS
Net cash provided by operating activities $ 452,158 $ 560,063 $1,230,925
------------------------------------------------------------------------------------------------------------
Cash flows from investing activities
Capital expenditures
Exploration and production (304,462) (207,374) (611,848)
Refining and marketing (36,018) (7,511) (83,989)
Transportation and other (7,663) (2,545) (3,445)
------------------------------------------------------------------------------------------------------------
Total capital expenditures (348,143) (217,430) (699,282)
Other, including proceeds from sales of
property, plant and equipment 4,845 13,895 19,627
------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (343,298) (203,535) (679,655)
------------------------------------------------------------------------------------------------------------
Cash flows from financing activities
Issuance (repayment) of notes 398,889 (95,314) (108,257)
Long-term borrowings 63,000 21,102 940
Repayment of long-term debt and
capitalized lease obligations (372,115) (336,224) (333,964)
Issuance of common stock -- -- --
Cash dividends paid (25,857) (23,757) (92,268)
Common and preferred stock retired (62,138) -- --
------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 1,779 (434,193) (533,549)
------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash 23,193 (728) 827
------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents $ 133,832 $ (78,393) $ 18,548
------------------------------------------------------------------------------------------------------------
STOCKHOLDER DATA AT YEAR-END
Number of common shares outstanding (in thousands)* 82,089 84,408 84,439
Number of stockholders (based on number of
holders of record) 19,343 23,696 25,497
Market price of common stock $ 24.88 $ 23.75 $ 27.25
============================================================================================================
</TABLE>
49
<PAGE> 44
TEN-YEAR SUMMARY OF OPERATING DATA
Amerada Hess Corporation and Consolidated Subsidiaries
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
1994 1993 1992
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
PRODUCTION PER DAY (NET)
Crude oil (barrels)
United States 55,638 60,173 62,517
Canada 10,581 11,536 11,528
United Kingdom (North Sea) 122,043 80,019 86,265
Norway (North Sea) 24,279 26,388 29,598
Abu Dhabi 7,273 10,004 11,150
Africa* 8,857 8,301 6,910
---------------------------------------------------------------------------------------------------
Total 228,671 196,421 207,968
---------------------------------------------------------------------------------------------------
Natural gas liquids (barrels)
United States 11,964 11,798 11,063
Canada 1,809 1,956 1,981
United Kingdom (North Sea) 6,756 3,783 1,468
Norway (North Sea) 1,320 1,432 1,707
---------------------------------------------------------------------------------------------------
Total 21,849 18,969 16,219
---------------------------------------------------------------------------------------------------
Natural gas (Mcf)
United States 427,103 502,459 601,824
Canada 185,856 167,839 137,680
United Kingdom (North Sea) 208,742 188,024 153,599
Norway (North Sea) 24,417 28,987 31,858
---------------------------------------------------------------------------------------------------
Total 846,118 887,309 924,961
---------------------------------------------------------------------------------------------------
WELL COMPLETIONS (NET)
Oil wells 28 48 33
Gas wells 44 49 20
Dry holes 24 37 22
PRODUCTIVE WELLS AT YEAR-END (NET)
Oil wells 2,160 2,189 2,082
Gas wells 1,146 1,115 966
---------------------------------------------------------------------------------------------------
Total 3,306 3,304 3,048
---------------------------------------------------------------------------------------------------
UNDEVELOPED NET ACREAGE (HELD AT END OF YEAR)
United States 1,685,000 1,854,000 1,819,000
Canada 743,000 788,000 840,000
Other international 3,827,000 3,522,000 2,328,000
---------------------------------------------------------------------------------------------------
Total 6,255,000 6,164,000 4,987,000
---------------------------------------------------------------------------------------------------
SHIPPING
Vessels owned or under charter at year-end 17 15 21
Total deadweight tons 2,265,000 2,398,000 3,223,000
REFINING (BARRELS DAILY)
Refinery crude runs 388,000 351,000 335,000
PETROLEUM PRODUCTS SOLD (BARRELS DAILY)
Gasoline, distillates and other light products 375,000 291,000 275,000
Residual fuel oils 93,000 95,000 102,000
---------------------------------------------------------------------------------------------------
Total 468,000 386,000 377,000
---------------------------------------------------------------------------------------------------
STORAGE CAPACITY AT YEAR-END (BARRELS) 94,597,000 94,380,000 95,199,000
NUMBER OF EMPLOYEES (AVERAGE) 9,858 10,173 10,263
===================================================================================================
</TABLE>
*Principally production from Gabon after 1990 and from Libya prior to June 30,
1986, when the Corporation ceased operations in accordance with United States
Government Regulations.
50
<PAGE> 45
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
1991 1990 1989 1988
---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
PRODUCTION PER DAY (NET)
Crude oil (barrels)
United States 66,063 62,434 60,992 60,782
Canada 11,966 9,494 9,178 9,251
United Kingdom (North Sea) 59,979 56,027 38,707 32,223
Norway (North Sea) 28,619 24,351 24,135 21,782
Abu Dhabi 9,866 8,475 7,230 9,374
Africa* 8,952 -- -- --
---------------------------------------------------------------------------------------------------------------------
Total 185,445 160,781 140,242 133,412
---------------------------------------------------------------------------------------------------------------------
Natural gas liquids (barrels)
United States 10,047 9,436 9,986 7,183
Canada 1,997 1,704 1,732 1,529
United Kingdom (North Sea) 766 805 466 295
Norway (North Sea) 1,752 2,004 2,016 1,884
---------------------------------------------------------------------------------------------------------------------
Total 14,562 13,949 14,200 10,891
---------------------------------------------------------------------------------------------------------------------
Natural gas (Mcf)
United States 583,740 457,042 335,112 283,114
Canada 104,151 76,768 72,855 61,653
United Kingdom (North Sea) 128,014 145,921 126,643 141,139
Norway (North Sea) 26,947 25,656 24,371 20,389
---------------------------------------------------------------------------------------------------------------------
Total 842,852 705,387 558,981 506,295
---------------------------------------------------------------------------------------------------------------------
WELL COMPLETIONS (NET)
Oil wells 45 17 19 39
Gas wells 41 33 19 8
Dry holes 36 38 31 35
PRODUCTIVE WELLS AT YEAR-END (NET)
Oil wells 2,103 2,111 2,048 2,014
Gas wells 927 905 714 612
---------------------------------------------------------------------------------------------------------------------
Total 3,030 3,016 2,762 2,626
---------------------------------------------------------------------------------------------------------------------
UNDEVELOPED NET ACREAGE (HELD AT END OF YEAR)
United States 1,802,000 1,716,000 1,589,000 1,556,000
Canada 842,000 835,000 582,000 786,000
Other international 2,638,000 2,494,000 2,501,000 3,936,000
---------------------------------------------------------------------------------------------------------------------
Total 5,282,000 5,045,000 4,672,000 6,278,000
---------------------------------------------------------------------------------------------------------------------
SHIPPING
Vessels owned or under charter at year-end 21 23 22 21
Total deadweight tons 2,825,000 3,012,000 3,081,000 2,719,000
REFINING (BARRELS DAILY)
Refinery crude runs 320,000 383,000 397,000 296,000
PETROLEUM PRODUCTS SOLD (BARRELS DAILY)
Gasoline, distillates and other light products 285,000 296,000 299,000 222,000
Residual fuel oils 128,000 132,000 171,000 157,000
---------------------------------------------------------------------------------------------------------------------
Total 413,000 428,000 470,000 379,000
---------------------------------------------------------------------------------------------------------------------
STORAGE CAPACITY AT YEAR-END (BARRELS) 94,879,000 93,867,000 91,794,000 90,798,000
NUMBER OF EMPLOYEES (AVERAGE) 10,317 9,645 8,740 8,151
=====================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------
1987 1986 1985
------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
PRODUCTION PER DAY (NET)
Crude oil (barrels)
United States 62,635 65,877 67,109
Canada 8,592 8,548 8,268
United Kingdom (North Sea) 27,709 32,955 32,212
Norway (North Sea) 20,937 17,088 17,896
Abu Dhabi 6,903 9,673 9,819
Africa* -- 15,375 26,878
------------------------------------------------------------------------------------------------------
Total 126,776 149,516 162,182
------------------------------------------------------------------------------------------------------
Natural gas liquids (barrels)
United States 5,913 2,944 4,932
Canada 1,306 1,627 1,576
United Kingdom (North Sea) 402 734 710
Norway (North Sea) 1,847 1,690 1,654
------------------------------------------------------------------------------------------------------
Total 9,468 6,995 8,872
------------------------------------------------------------------------------------------------------
Natural gas (Mcf)
United States 282,906 228,827 244,062
Canada 49,229 46,248 57,297
United Kingdom (North Sea) 180,594 168,926 164,443
Norway (North Sea) 18,771 15,230 15,765
------------------------------------------------------------------------------------------------------
Total 531,500 459,231 481,567
------------------------------------------------------------------------------------------------------
WELL COMPLETIONS (NET)
Oil wells 35 23 45
Gas wells 13 6 21
Dry holes 28 25 47
PRODUCTIVE WELLS AT YEAR-END (NET)
Oil wells 2,058 2,056 2,149
Gas wells 620 616 626
------------------------------------------------------------------------------------------------------
Total 2,678 2,672 2,775
------------------------------------------------------------------------------------------------------
UNDEVELOPED NET ACREAGE (HELD AT END OF YEAR)
United States 1,566,000 1,949,000 2,543,000
Canada 787,000 851,000 1,933,000
Other international 3,875,000 3,626,000 3,567,000
------------------------------------------------------------------------------------------------------
Total 6,228,000 6,426,000 8,043,000
------------------------------------------------------------------------------------------------------
SHIPPING
Vessels owned or under charter at year-end 21 22 23
Total deadweight tons 2,903,000 2,953,000 2,978,000
REFINING (BARRELS DAILY)
Refinery crude runs 371,000 293,000 337,000
PETROLEUM PRODUCTS SOLD (BARRELS DAILY)
Gasoline, distillates and other light products 257,000 207,000 270,000
Residual fuel oils 154,000 151,000 147,000
------------------------------------------------------------------------------------------------------
Total 411,000 358,000 417,000
------------------------------------------------------------------------------------------------------
STORAGE CAPACITY AT YEAR-END (BARRELS) 88,047,000 87,746,000 88,839,000
NUMBER OF EMPLOYEES (AVERAGE) 7,890 7,776 8,290
======================================================================================================
</TABLE>
51
<PAGE> 1
EXHIBIT 21
AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUBSIDIARIES OF THE REGISTRANT
Organized under
Name of Subsidiary the laws of
------------------ ---------------
Amerada Hess Canada Ltd. ................................ Canada
Amerada Hess Limited .................................... United Kingdom
Amerada Hess Norge A/S .................................. Norway
Amerada Hess Oil Corporation of Abu Dhabi ............... Delaware
Amerada Hess Pipeline Corporation ....................... Delaware
Amerada Hess (Port Reading) Corporation ................. Delaware
Amerada Hess Production Gabon ........................... Gabon
Amerada Hess Shipping Corporation ....................... Liberia
Caribbean Capital (Barbados) Limited .................... Barbados
Hess Oil St. Lucia Limited .............................. St. Lucia
Hess Oil Virgin Islands Corp. ........................... U.S. Virgin Islands
Jamestown Insurance Company Limited ..................... Bermuda
Seal Island Shipping Corporation ......................... Liberia
Other subsidiaries (names omitted because such unnamed subsidiaries, considered
in the aggregate as a single subsidiary, would not constitute a significant
subsidiary)
Each of the foregoing subsidiaries conducts business under the name listed, and
is 100% owned by the Registrant, except for Amerada Hess Production Gabon,
which is 55% owned by the Registrant.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<CASH> 53,135
<SECURITIES> 0
<RECEIVABLES> 570,525
<ALLOWANCES> 0
<INVENTORY> 945,635
<CURRENT-ASSETS> 1,721,661
<PP&E> 14,304,826
<DEPRECIATION> 7,938,824
<TOTAL-ASSETS> 8,337,940
<CURRENT-LIABILITIES> 1,201,414
<BONDS> 3,154,235
<COMMON> 92,996
0
0
<OTHER-SE> 3,006,633
<TOTAL-LIABILITY-AND-EQUITY> 8,337,940
<SALES> 6,601,984
<TOTAL-REVENUES> 6,698,793
<CGS> 4,449,819
<TOTAL-COSTS> 4,449,819
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 245,149
<INCOME-PRETAX> 235,812
<INCOME-TAX> 162,098
<INCOME-CONTINUING> 73,714
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 73,714
<EPS-PRIMARY> 0.79
<EPS-DILUTED> 0.79
</TABLE>
