<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
(MARK ONE)
<TABLE>
<S> <C>
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
</TABLE>
COMMISSION FILE NO. 1-10053
------------------------
ORYX ENERGY COMPANY
(Exact name of Registrant as specified in its charter)
<TABLE>
<S> <C>
DELAWARE 23-1743284
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification number)
13155 NOEL ROAD 75240-5067
DALLAS, TEXAS
(Address of principal executive (Zip code)
offices)
</TABLE>
Registrant's telephone number, including area code:
(214) 715-4000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
<TABLE>
<CAPTION>
Name of Each Exchange
Title of Each Class on Which Registered
- -------------------------------------------------------- --------------------------------------------------------
<S> <C>
COMMON STOCK, $1 PAR VALUE NEW YORK STOCK EXCHANGE
9 3/4% NOTES DUE SEPTEMBER 15, 1998 NEW YORK STOCK EXCHANGE
10 3/8% DEBENTURES DUE SEPTEMBER 15, 2018 NEW YORK STOCK EXCHANGE
7 1/2% CONVERTIBLE SUBORDINATED
DEBENTURES DUE MAY 15, 2014 NEW YORK STOCK EXCHANGE
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
MEDIUM TERM NOTES, SERIES A DUE NOVEMBER 28, 1994 THROUGH FEBRUARY 1, 2002
9.30% NOTES DUE MAY 1, 1996
10% NOTES DUE JUNE 15, 1999
9 1/2% NOTES DUE NOVEMBER 1, 1999
10% NOTES DUE APRIL 1, 2001
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. / /
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 ____
The aggregate market value of voting stock held by nonaffiliates of the
Registrant as of February 28, 1994, was approximately $1,742 million.
The number of shares of Common Stock, $1 par value, outstanding as of
February 28, 1994, was 96,946,069.
Selected portions of the Oryx Energy Company definitive Proxy Statement,
which will be filed with the Securities and Exchange Commission within 120 days
after December 31, 1993, are incorporated by reference in Part III of this Form
10-K.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
CERTAIN ABBREVIATIONS AND OTHER MATTERS
As used herein, the following terms have specific meanings: "m" means
thousand, "mm" means million, "bbl" means barrel, "mb" means thousands of
barrels, "mmb" means millions of barrels, "mcf" means thousand cubic feet,
"mmcf" means million cubic feet, "bcf" means billion cubic feet, "eb" means
equivalent barrel, "mmeb" means millions of equivalent barrels, "b/d" means
barrels per day, "mmcf/d" means million cubic feet per day, "mmbtu"means million
British thermal units, "ED&A" means exploration, development and acquisition and
"FD&A" means finding, development and acquisition.
Natural gas equivalents are determined under the relative energy content
method by using the ratio of 6.0 mcf of natural gas to 1.0 bbl of crude oil,
condensate or natural gas liquids.
With respect to information on the working interest in wells, drilling
locations and acreage, "net" oil and gas wells, drilling locations and acres are
determined by multiplying "gross" oil and gas wells, drilling locations and
acres by Oryx Energy Company's working interest in such wells, drilling
locations or acres.
<PAGE>
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
Oryx Energy Company (together with its consolidated subsidiaries, unless the
context otherwise requires, Company) engages exclusively in the exploration and
development of oil and gas. The Company has a strong base of U.S. and
international reserves and high-potential exploration and development projects
in key areas such as the Gulf of Mexico, the U.K. North Sea and Indonesia. The
Company's business in the United States is conducted through Sun Energy
Partners, L.P. (Partnership), of which the Company is the Managing General
Partner. At December 31, 1993, the Company had a 98 percent ownership interest
in the Partnership.
The Company's mission is to create value for its shareholders. To achieve
this objective, the Company has three primary operating strategies:
INTERNATIONAL. The emphasis on international provides the Company with
prospects for growth in areas of higher potential, such as the many
development projects in the U.K. North Sea and the exploration prospects in
the U.K., Indonesia and Algeria.
GULF OF MEXICO. The Company is focusing its domestic efforts on
high-potential Gulf of Mexico prospects, including the continental shelf,
subsalt and flex trend.
TECHNOLOGY. The Company is continuing to apply advanced technology on a
worldwide basis to reduce risk and lower costs. Dedicating resources to
advanced 3-D seismic processing and interpretation, hydrocarbon indicator
technologies, and horizontal drilling applications are strengths which the
Company believes create a competitive advantage relative to its peers.
These strategies have resulted in competitive production replacement and
FD&A costs. For the five years 1989 through 1993, the Company's average
production replacement rate was 154 percent at a cost of $4.64 per eb. In 1993,
the Company replaced 103 percent of its production at $5.53 per eb.
The Company determines its ED&A spending plans primarily based on the cash
flow that it expects to generate. For 1993, the Company spent $451 million for
ED&A. The Company plans to spend approximately $370 milliion for ED&A in 1994,
with the primary emphasis being near-term volume additions. In the current low
oil price environment, the highest priorities for the Company are to increase
its production volumes and to preserve it financial strength. By concentrating
and highgrading its exploration and development projects and successfully
applying technology, the Company has been able to substantially reduce its
spending levels and achieve reserve replacement rates at competitive costs.
PROVED RESERVES
As of December 31, 1993, the Company's proved reserves were an estimated 508
mmbbl of liquids and an estimated 1,881 bcf of natural gas which represents an
aggregate of 822 mmeb of reserves. The Company's liquids reserves were located
in the United States (51 percent), the United Kingdom (37 percent), Indonesia (7
percent) and other foreign countries (5 percent). The Company's natural gas
reserves were located in the United States (76 percent) and the United Kingdom
(24 percent). More information on the estimated quantities of proved oil and gas
reserves and information on proved developed oil and gas reserves, as well as
information concerning the Standardized Measure, are presented in the
"Consolidated Financial Statements -- Supplementary Financial and Operating
Information" included in Item 8 herein. The Company files estimates of oil and
gas reserve data with various governmental regulatory authorities and agencies.
The basis of reporting reserves to these authorities and agencies in some cases
may not be comparable. However, the difference in estimates does not exceed five
percent.
2
<PAGE>
OFFSHORE UNITED STATES
The Company has identified the Gulf of Mexico, an area offering proven
potential and well developed infrastructure, as a key part of its growth
strategy.
EXPLORATION
As of December 31, 1993, the Company held 388 thousand net undeveloped acres
offshore, as compared to 298 thousand as of December 31, 1992. The Company owns
interests in 173 Gulf of Mexico blocks of which 124 are undeveloped. In 1993,
the Company spent $6.5 million to acquire interests in 20 blocks.
As of December 31, 1993, the Company was in the process of drilling two
gross and two net exploratory wells. The Company drilled four net exploratory
wells offshore in 1993 and four in 1992.
The Company's offshore exploration program, concentrated in the Gulf of
Mexico, has three major objectives. The first objective is the gas-prone
prospects in the shallower water depths (less than 600 feet). The second
objective is in the subsalt which covers part of the continental shelf and the
deeper part of the Gulf of Mexico in water depths ranging from 300 to 2,000
feet. The third objective is in the deeper waters of the flex trend area (600 to
2,000 feet). Advanced hydrocarbon indicator and three-dimensional seismic
technologies are being used to explore undeveloped acreage as well as blocks
held by production.
The Company owns a 100 percent interest in the four block High Island 384
unit. The High Island 384 unit is composed of blocks 378, 379, 384 and 385 and
is located approximately 112 miles off the Texas coast in water with an average
depth of approximately 360 feet. In 1993, the Company announced an oil discovery
in High Island 379. The HI-A-379 #1 discovery well encountered 179 feet of oil
pay from three Pleistocene sands between 4,600 and 5,130 feet. In the early part
of 1994, the Company announced an oil and gas discovery in High Island 385. The
High Island 385 discovery encountered 80 feet of net pay in two Basal Nebraskan
sands between 14,300 and 14,410 feet. The combined production from the two
discoveries is expected to peak at approximately 20 meb per day. This new
development is expected to begin production in 1995.
PRODUCTION AND DEVELOPMENT
Average daily production of crude oil and condensate offshore was 8.6, 7.2
and 5.4 mb in 1993, 1992 and 1991. Average daily production of natural gas
offshore was 193, 181 and 185 mmcf in 1993, 1992 and 1991. The increase in 1993
natural gas production was due primarily to the Mississippi Canyon unit.
The Company began production from its Mississippi Canyon 400 unit in July
1993. The unit lies in water depths ranging from 600 to 2,100 feet off of the
Louisiana coast. The Company used subsea completions to tie three wells into an
existing platform. Production from this unit reached 60 mmcf of gas per day. The
Company has a 100 percent working interest in this project.
Delineation of Garden Banks 260 located in the deep flex trend area of the
Gulf of Mexico is continuing. First production is anticipated in 1998 at a gross
rate of about 60,000 eb/d. The Company owns a 50 percent interest in a three
block area.
Viosca Knoll 826, lies 80 miles off the Alabama coast in water depths of
1,500 to 2,500 feet. First production is anticipated in 1996 or 1997 with a
gross peak rate of 20,000 to 30,000 eb/d. The Company operates the 4 block
Viosca Knoll unit and owns a 50 percent interest.
As of December 31, 1993, the Company was in the process of drilling 7 gross
and 2 net development wells. The Company drilled 8 net development wells
offshore in 1993 and 2 in 1992. Of the 8 net development wells drilled in 1993,
5 were successful.
3
<PAGE>
ONSHORE UNITED STATES
The onshore area continues to be an important contributor of production
volumes and cash flow. While the Company continues to pursue workovers and
development opportunities to enhance its production and cash flows, ED&A
spending for the onshore U.S. in total has declined substantially since 1991 as
a result of the redeployment of the Company's resources in its key areas.
EXPLORATION
The decrease of 387 thousand net undeveloped acres from 820 thousand at
December 31, 1992 to 433 thousand at December 31, 1993 is due to the
relinquishment of non-producing properties as part of the Company's strategic
plan to reduce onshore exploration.
The Company drilled 3 fewer net exploratory wells onshore in 1993 than 1992
and 17 fewer in 1992 than in 1991.
PRODUCTION AND DEVELOPMENT
Average daily production of crude oil and condensate onshore was 47.3, 56.2
and 70.4 mb in 1993, 1992 and 1991. The decrease in 1993 crude oil and
condensate production compared to 1992 and in 1992 compared to 1991 was due
primarily to asset sales and normal declines. Average daily net production of
natural gas onshore was 330, 403 and 466 mmcf in 1993, 1992 and 1991. The
decrease in 1993 natural gas production compared to 1992 and in 1992 compared to
1991 was due primarily to divestments.
As of December 31, 1993, the Company was in the process of drilling or
participating in the drilling of 14 gross and 8 net development wells onshore.
Of the 45 net development wells drilled onshore, 44 were successful during 1993.
Net development wells drilled onshore during 1993 decreased by 12 from 57 in
1992 and decreased in 1992 by 43 from 100 in 1991 primarily due to the de-
emphasis of onshore activities.
As part of its asset sale program, the Company sold substantially all its
gas processing plant business in 1992. The Company's remaining gas plant
business at December 31, 1993 consisted of 11 operated gas processing plants and
interests in 4 others.
UNITED KINGDOM
The Company has seven producing fields, four major development projects and
several exploration prospects in the North Sea. Reserves have grown considerably
since the Company acquired its interests in these fields in 1990. Reserves added
at the date of acquisition were 206 mmeb. After producing 53 mmeb over the past
three years, the Company's reserves are estimated to be 263 mmeb as of December
31, 1993.
EXPLORATION
The Company held 259 thousand net undeveloped acres in the North Sea as of
December 31, 1993, compared to 297 thousand net undeveloped acres as of December
31, 1992.
The Company was participating in the drilling of 1 gross exploratory well in
the North Sea at December 31, 1993.
PRODUCTION AND DEVELOPMENT
The Company's producing fields set forth in the table below, are located in
the northern and central sectors of the North Sea with the exception of the
Audrey Field, which is located in the southern gas basin.
As of December 31, 1993, the Company was in the process of drilling or
participating in the drilling of 6 gross and 1 net development well in the North
Sea.
The Company's average daily net production of crude oil and condensate in
the United Kingdom was 35.2, 35.4 and 36.5 mb during 1993, 1992 and 1991.
Average daily production of natural gas was 80, 95 and 51 mmcf during 1993, 1992
and 1991. The decrease in net daily production of natural gas in
4
<PAGE>
1993 compared to 1992 was due to a temporary shutdown of the pipeline system
serving Audrey. The changes in gas volumes in 1992 as compared to 1991 were
primarily due to a redetermination which increased the Company's interest in
Audrey in the third quarter of 1991.
The following table sets forth the North Sea producing fields and their net
daily production:
<TABLE>
<CAPTION>
1993 NET
DAILY
PERCENT PRODUCTION
PRODUCING FIELDS OIL/GAS OWNERSHIP (MEB)
- ------------------------------------------------------------------ --------- ------------- -------------
<S> <C> <C> <C>
Audrey............................................................ Gas 33.6 13.3
Dunlin............................................................ Oil 14.4 5.7
Hutton............................................................ Oil 22.2 4.9
Murchison......................................................... Oil 25.9 6.0
Ninian............................................................ Oil 29.5 14.4
Lyell............................................................. Oil 33.3 4.2
Strathspey........................................................ Oil/Gas 6.5 --
---
Total......................................................... 48.5
---
---
</TABLE>
In December 1993, the Company increased its interest in Ninian to 29.5
percent by acquiring an additional 8.2 percent interest in the Ninian Field and
related facilities. The Company's net production from the Ninian Field will
increase from approximately 15,000 bbls per day to approximately 20,000 bbls per
day. The Company also receives tariff income on production from several
satellite fields that produce through the Ninian facilities.
In 1993, the Company began production on two North Sea development projects.
Lyell, a subsea satellite facility, began producing in 1993 and peaked at 10,000
bbls of oil per day net. The Company has a 33.3 percent working interest in the
Lyell Field. The second subsea satellite facility, Strathspey, began production
in the last week of 1993. The Company has a 6.5 percent working interest in the
Strathspey Field. Production from Lyell and Strathspey is transported to the
Ninian platforms.
In early 1994, the Company began production on a third development project,
Alba, which is located on block 16/26 in the central North Sea. Daily gross
production is expected to peak at a rate of 75,000 bbls. The Company owns a 15.5
percent interest in the block. In the central North Sea, the Company has two
fields underlying its 16/26 block which, based on the Company's 15.5 percent
working interest, represents more than 100 net mmeb of reserves. At about 6,000
feet is the Alba oil field, one of the five largest development projects in the
North Sea. Underlying the Alba oil field, at approximately 13,000 feet, is the
Britannia Field, the largest gas condensate development project in the North
Sea, which extends over five blocks. Recent appraisal wells continue to confirm
the significance of this large gas and condensate field. The Britannia Field is
subject to unitization, and the Company currently has a 6.2 percent cost-sharing
interest in the field.
The Company also has four North Sea developments where discoveries have been
made and confirmation wells drilled. They are located in the northern sector
(Columba), in the central sector (Alba Phase II and Britannia) and the southern
gas basin (Galleon). In total, the Company has 38 blocks in the North Sea. The
following table outlines the North Sea prospective developments, with their
expected start-up dates and estimated daily net peak production:
<TABLE>
<CAPTION>
DAILY NET PEAK
YEAR OF PERCENT PRODUCTION
DEVELOPMENT PROJECTS OIL/GAS START-UP OWNERSHIP (MEB)
- --------------------------------------------------------- ----------- ----------- ------------ ---------------
<S> <C> <C> <C> <C>
Galleon.................................................. Gas 1994 10.0* 3
Columba.................................................. Oil 1994 28.0 2
Britannia................................................ Gas 1998 6.2* 12
Alba Phase II............................................ Oil 1998 15.5 8
<FN>
- ------------------------
*Estimated; subject to unitization.
</TABLE>
5
<PAGE>
In addition, the Company has interests in North Sea transportation systems,
terminal storage facilities and certain other related income producing assets,
including the Brent and Ninian Pipeline Systems and the Sullom Voe Terminal in
the Shetland Islands.
INDONESIA
The Company acquired interests in three production sharing contracts in
Indonesia in 1990 as part of the international properties acquisition. Since
that time, it has successfully participated in the development of the Intan,
Widuri and KF fields within their contract areas. In addition, the Company added
new exploration areas to the portfolio including the large Brantas area in Java.
EXPLORATION
As of December 31, 1993, the Company held 1,126 thousand net undeveloped
acres in Indonesia compared to 1,086 at December 31, 1992.
As of December 31, 1993, the Company was in the process of drilling or
participating in the drilling of 2 gross and 1 net exploratory well in
Indonesia.
PRODUCTION AND DEVELOPMENT
The Company's average daily net production of crude oil and condensate in
Indonesia was 15.0, 18.0 and 24.3 mb during 1993, 1992 and 1991. The decrease in
net daily production during 1993 as compared to 1992 was due to normal declines
from mature fields.
The following table sets forth Indonesian producing areas and their net
daily production:
<TABLE>
<CAPTION>
1993 NET
DAILY
PERCENT PRODUCTION
CONTRACT AREA OWNERSHIP (MEB)
- ----------------------------------------------------------------- ------------- -------------
<S> <C> <C>
Malacca Strait................................................... 21.5 6.5
Kakap............................................................ 18.8 3.0
Southeast Sumatra................................................ 3.7 5.5
---
Total........................................................ 15.0
---
---
</TABLE>
The Company has made a platform decision on the KRA-KG fields which are
within the Kakap Contract Area. Development drilling is expected to commence in
late 1994. The fields will be tied into existing production facilities.
Production is expected to commence in early 1995 with peak daily gross
production of 63,000 bbls.
As of December 31, 1993, the Company was in the process of drilling or
participating in the drilling of 1 gross development well in Indonesia.
OTHER FOREIGN
The Company acquired interests in Ecuador and Gabon in 1990. Development
activities are planned for both of these areas in 1994. In Ecuador, the Gacela
field began producing in 1993 and a decision to proceed with development of the
Jaguar field has been made. The Company has supplemented its acreage through
interests in a license off the Northwest Shelf of Australia and with a 25
percent interest in the Hassi Dzabat and the Mehaiguene production sharing
contracts in Algeria. The Company will continue to evaluate opportunities in
other areas.
EXPLORATION
As of December 31, 1993, the Company held 1,848 thousand net undeveloped
acres in other foreign properties, as compared to 1,089 thousand net undeveloped
acres as of December 31, 1992. The increase of 759 thousand net undeveloped
acres in 1993 as compared to 1992 is due to an additional production sharing
contract obtained by the Company in Algeria.
6
<PAGE>
PRODUCTION AND DEVELOPMENT
The Company's average daily net production of crude oil and condensate from
other foreign areas was 3.7, 2.4 and 3.3 mb in 1993, 1992 and 1991. The average
daily production of crude oil and condensate increased in 1993, compared to
1992, due to the Company's increased working interest in the unitized
Coca-Payamino Field in Ecuador from 17.5 percent to 23.0 percent. In Gabon, the
Company has a 14.25 percent working interest in the Oguendjo Production Sharing
Contract.
As of December 31, 1993, the Company was in the process of drilling or
participating in the drilling of 3 gross and 1 net development well.
PRODUCTION
The Company's production is concentrated primarily in the United States, the
United Kingdom and Indonesia. In 1993, the Company produced 55.8 mmeb from its
properties in the United States, 17.8 mmeb from its properties in the United
Kingdom, 5 mmeb from its properties in Indonesia and 1 mmeb from its other
foreign properties.
The following table sets forth the Company's average daily net production
for 1993, 1992 and 1991:
AVERAGE DAILY NET PRODUCTION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Crude & Condensate:
(Thousands of barrels daily)
United States
Onshore................................................................ 47.3 56.2 70.4
Offshore............................................................... 8.6 7.2 5.4
--------- --------- ---------
55.9 63.4 75.8
--------- --------- ---------
U.K.................................................................... 35.2 35.4 36.5
Indonesia.............................................................. 15.0 18.0 24.3
Other foreign.......................................................... 3.7 2.4 3.3
--------- --------- ---------
53.9 55.8 64.1
--------- --------- ---------
Processed Natural Gas Liquids:*
(Thousands of barrels daily)
United States.......................................................... 7.4 19.7 27.7
--------- --------- ---------
117.2 138.9 167.6
--------- --------- ---------
--------- --------- ---------
Natural Gas:**
(Millions of cubic feet daily)
United States
Onshore................................................................ 330 403 466
Offshore............................................................... 193 181 185
--------- --------- ---------
523 584 651
U.K...................................................................... 80 95 51
--------- --------- ---------
603 679 702
--------- --------- ---------
--------- --------- ---------
<FN>
- ------------------------
*The Company sold substantially all of its United States gas plant business
during 1992. (See Note 4 to the Consolidated Financial Statements included in
Item 8 herein.)
**Natural gas production includes unprocessed natural gas liquids.
</TABLE>
7
<PAGE>
ACREAGE, WELLS AND PER UNIT DATA
The following table sets forth the Company's undeveloped and developed oil
and gas acreage (in thousands) held at December 31, 1993 and 1992:
UNDEVELOPED ACREAGE
<TABLE>
<CAPTION>
GROSS NET
-------------------- --------------------
1993 1992 1993 1992
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
United States
Onshore...................................................... 997 1,752 433 820
Offshore..................................................... 674 605 388 298
--------- --------- --------- ---------
1,671 2,357 821 1,118
U.K............................................................ 889 978 259 297
Indonesia...................................................... 2,866 5,064 1,126 1,086
Other Foreign.................................................. 6,783 3,663 1,848 1,089
--------- --------- --------- ---------
12,209 12,062 4,054 3,590
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
DEVELOPED ACREAGE
<TABLE>
<CAPTION>
GROSS NET
-------------------- --------------------
1993 1992 1993 1992
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
United States
Onshore...................................................... 1,599 2,416 870 1,239
Offshore..................................................... 253 268 104 116
--------- --------- --------- ---------
1,852 2,684 974 1,355
U.K............................................................ 174 174 67 64
Indonesia...................................................... 6,426 7,035 819 842
Other Foreign.................................................. 98 98 80 56
--------- --------- --------- ---------
8,550 9,991 1,940 2,317
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
8
<PAGE>
The following table sets forth the Company's net exploratory and development
oil and gas wells drilled during 1993, 1992 and 1991:
EXPLORATORY WELLS DRILLED
<TABLE>
<CAPTION>
GROSS NET
------------------------------- -------------------------------
1993 1992 1991 1993 1992 1991
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Oil
United States
Onshore................................................. -- 3 4 -- 1 4
Offshore................................................ 2 1 3 1 1 2
--- --- --- --- --- ---
2 4 7 1 2 6
U.K....................................................... -- 1 2 -- -- --
Indonesia................................................. -- 6 3 -- 1 1
Other foreign............................................. 2 1 1 1 1 1
Gas
United States
Onshore................................................. -- 2 3 -- 1 1
Offshore................................................ 1 3 3 1 3 1
--- --- --- --- --- ---
1 5 6 1 4 2
U.K....................................................... -- 1 -- -- -- --
Dry
United States
Onshore................................................. 2 6 31 2 3 17
Offshore................................................ 4 1 5 2 -- 2
--- --- --- --- --- ---
6 7 36 4 3 19
U.K....................................................... 3 3 8 1 1 2
Indonesia............................................... 9 7 12 1 1 1
Other foreign........................................... 2 1 -- 1 -- --
--- --- --- --- --- ---
25 36 75 10 13 32
--- --- --- --- --- ---
--- --- --- --- --- ---
</TABLE>
9
<PAGE>
DEVELOPMENT WELLS DRILLED
<TABLE>
<CAPTION>
GROSS NET
------------------------------- -----------------------------------
1993 1992 1991 1993 1992 1991
--------- --------- --------- ----- ----- ---------
<S> <C> <C> <C> <C> <C> <C>
Oil
United States
Onshore................................................. 44 69 130 29 43 79
Offshore................................................ 4 -- -- 2 -- --
-- --
--- --- --- ---
48 69 130 31 43 79
U.K....................................................... 5 2 4 1 -- 1
Indonesia................................................. 29 26 18 3 3 1
Other foreign............................................. 7 2 3 2 1 1
Gas
United States
Onshore................................................. 38 26 54 15 11 19
Offshore................................................ 8 7 16 3 2 7
-- --
--- --- --- ---
46 33 70 18 13 26
U.K....................................................... -- -- -- -- -- --
Dry
United States
Onshore................................................. 1 4 3 1 3 2
Offshore................................................ 4 -- -- 3 -- --
-- --
--- --- --- ---
5 4 3 4 3 2
U.K....................................................... 6 -- -- 1 -- --
Indonesia................................................. 1 6 3 -- 1 --
Other foreign............................................. 1 -- -- -- -- --
-- --
--- --- --- ---
148 142 231 60 64 110
-- --
-- --
--- --- --- ---
--- --- --- ---
</TABLE>
The following table sets forth the Company's gross and net producing oil and
gas wells at December 31, 1993:
PRODUCING OIL AND GAS WELLS
<TABLE>
<CAPTION>
GROSS* NET
-------------------- --------------------
OIL GAS OIL GAS
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
United States
Onshore........................................................... 4,586 988 2,203 577
Offshore.......................................................... 60 159 22 66
--------- --------- --------- ---------
4,646 1,147 2,225 643
Foreign:
U.K............................................................... 134 11 31 4
Indonesia......................................................... 385 1 32 --
Other foreign..................................................... 35 -- 7 --
--------- --------- --------- ---------
Total 5,200 1,159 2,295 647
--------- --------- --------- ---------
--------- --------- --------- ---------
<FN>
- ------------------------
*Gross producing wells include 180 multiple completion wells (more than one
formation producing into the same well bore).
</TABLE>
10
<PAGE>
The following table sets forth the Company's average revenues and production
costs per unit of oil and gas production for 1993, 1992 and 1991:
AVERAGE PER UNIT REVENUES AND PRODUCTION COSTS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Revenues:
Crude and condensate (per bbl)
U.S.................................................................. $ 15.96 $ 18.51 $ 20.88
U.K.................................................................. $ 15.82 $ 19.14 $ 21.72
Indonesia............................................................ $ 17.76 $ 19.21 $ 19.98
Other foreign........................................................ $ 16.91 $ 16.95 $ 17.04
Worldwide............................................................ $ 16.08 $ 18.77 $ 20.85
Crude, condensate and natural gas liquids (per bbl)
U.S.................................................................. $ 14.08 $ 18.21 $ 20.45
Natural Gas (per mcf)
U.S.................................................................. $ 1.96 $ 1.72 $ 1.55
U.K.................................................................. $ 2.11 $ 2.50 $ 2.69
Worldwide............................................................ $ 1.98 $ 1.83 $ 1.63
Average production cost per unit of oil and gas production (per eb):*
U.S.................................................................. $ 4.57 $ 4.20 $ 3.73
U.K.................................................................. $ 7.67 $ 8.88 $ 9.53
Indonesia............................................................ $ 12.97 $ 12.37 $ 12.43
Other foreign........................................................ $ 7.19 $ 8.10 $ 8.85
Worldwide............................................................ $ 5.95 $ 6.28 $ 6.06
<FN>
- ------------------------
*Average production cost consists of operating cost and production taxes.
</TABLE>
ASSET DISPOSITIONS
Assets are managed on a portfolio basis. The Company will continue to buy
and sell assets with the intention of upgrading its asset base.
RECOVERY METHODS
During 1993, the Company obtained 49, 39 and 12 percent of its U.S. crude
production from primary, secondary and tertiary recovery methods. This compares
to 50, 38 and 12 percent of its crude oil production in 1992. At December 31,
1993, the Company operated or participated in 18 major tertiary oil recovery
programs that produced approximately 6 thousand net barrels of crude and
condensate daily.
The terms "secondary recovery" and "tertiary recovery" relate to those
methods used to increase the quantity of crude oil and condensate and natural
gas that can be recovered in excess of the quantity recoverable using the
primary energy found in a reservoir. Secondary recovery methods include pressure
maintenance by waterflooding or natural gas injection. Tertiary recovery methods
include injection of carbon dioxide, nitrogen, chemicals, steam or a combination
of these with natural gas or water. Tertiary and, to a lesser extent, secondary
recovery operations generally have higher operating costs compared to those
incurred in primary production efforts.
MARKETING OF OIL AND GAS
DISTRIBUTION
Crude oil, condensate and natural gas are distributed in the U.S. through
pipelines and/or trucks to end users, gatherers and transportation companies and
in foreign locations by tanker and/or
11
<PAGE>
pipeline to traders and end users. Sufficient distribution systems exist and are
readily available in the areas of the Company's production to enable the Company
to effectively market its oil and gas. In some instances, the Company owns an
interest in these systems.
CRUDE AND CONDENSATE
During 1993, sales to Koch Refining International totaled approximately 12
percent, and sales to Phibro Energy USA, Inc. totaled approximately 10 percent
of the Company's sales of crude oil and condensate. No other customer purchased
more than 9 percent of the Company's sales of crude oil and condensate.
Since most of the Company's crude and condensate is produced in areas where
there are other buyers offering to purchase at market prices, the Company
believes that the loss of any major purchaser would not have a material adverse
effect on the Company's business. In 1993, the ten largest customers, including
Koch Refining International and Phibro Energy USA, Inc., accounted for
approximately 62 percent of such sales.
Currently, approximately 55 percent of domestic sales are made pursuant to
arrangements that are cancelable upon 30 days' written notice by the Company or
the purchaser, with substantially all of the remainder of the domestic
production being sold pursuant to contracts of varying terms of up to one year
in length.
The Company markets its foreign crude oil production, which is sold under
short-term contracts, on a cargo lot basis.
NATURAL GAS
The Company's natural gas marketing strategies in the U.S. are designed to
be effective in the current competitive environment. Sales of natural gas into
short-term markets averaged 57 percent of total sales. However, by year-end
nearly 50 percent of total sales were contracted to end-users of natural gas on
a long term basis. The Company's strategy is to sell to end-users that possess
firm transportation rights from the producing basin to the city gate on major
interstate pipelines. Contract length of these term sales ranges from one to ten
years.
The Company sells its natural gas production from the North Sea under
long-term agreements with British Gas plc under which prices are reset annually
in sterling based on a variety of factors including prevailing oil prices. Sales
to British Gas plc represented 14 percent of the Company's natural gas sales for
1993.
During 1993, British Gas plc was the only customer who accounted for more
than 4 percent of the Company's natural gas sales. The ten largest customers
accounted for approximately 38 percent of total gas sales during 1993.
HEDGING
Because of the volatility of oil and gas prices, the Company periodically
enters into crude oil and natural gas hedging activities. (See Note 1 to the
Consolidated Financial Statements included in Item 8 herein).
REGULATION
GENERAL
The oil and gas industry is subject to regulation by the public policies of
national, state and local governments relating to such matters as the award of
exploration and production interests, the imposition of specific drilling
obligations, environmental protection controls, control over the development and
abandonment of a field (including restrictions on production and abandonment of
production facilities) and, in some cases, possible nationalization,
expropriation, regulatory taking, cancellation or frustration of contract
rights. The industry is also subject to the payment of royalties and taxes,
which tend to be high compared to those levied on other commercial activities.
The Company cannot predict the impact of future regulatory and taxation
initiatives.
12
<PAGE>
NATURAL GAS
The natural gas industry in the United States remains under federal
regulation pursuant to the Natural Gas Act and the Natural Gas Policy Act.
However, as a result of the Natural Gas Decontrol Act, wellhead regulation of
gas prices ended January 1, 1993.
ENVIRONMENTAL MATTERS
The Company is subject to, and makes every effort to comply with, various
environmental quality control regulations of national, state and local
governments. Although environmental requirements can have a substantial impact
upon the energy industry, generally these requirements do not appear to affect
the Company any differently or to any greater or lesser extent than other
exploration and production companies.
The Company has been named as a potentially responsible party (PRP) at four
sites pursuant to the Comprehensive Environmental Response, Compensation, and
Liability Act of 1980, as amended. At two of these sites, the Company has been
named as a de minimis party and therefore expects its liability to be small. At
a third site, the Company is reviewing its options and anticipates that it will
participate in steering committee activities with the Environmental Protection
Agency. At the fourth and largest site, the Operating Industries, Inc. site in
California, the Company has participated in a steering committee consisting of
139 companies. The steering committee and other PRP's previously entered into
two partial consent decrees with the EPA providing for remedial actions which
have been or are to be completed. The steering committee has recently
successfully negotiated a third partial consent decree which provides for the
following remedial actions: a clay cover, methane capturing wells, and leachate
destruction facilities. The remaining work at the site involves groundwater
evaluation and long-term operation and maintenance.
Based on the facts outlined above and the Company's ongoing analyses of the
actions where it has been identified as a PRP, the Company believes that it has
accrued sufficient reserves to absorb the ultimate cost of such actions and that
such costs therefore will not have a material impact on the Company's financial
condition or results of operations. While liability at superfund sites is
typically joint and several, the Company has no reason to believe that defaults
by other PRPs will result in liability of the Company materially larger than
expected.
COMPETITION
The oil and gas industry is highly competitive. Integrated companies,
independent companies and individual producers and operators are active bidders
for desirable oil and gas properties, as well as for the equipment and labor
required to operate and develop such properties. Although several of these
competitors have financial resources substantially greater than those of the
Company, management believes that the Company is in a position to compete
effectively.
The availability of a ready market for the Company's oil and gas production
depends on numerous factors beyond its control, including the level of prices
and consumer demand, the extent of worldwide oil and gas production, the cost
and availability of alternative fuels, the cost and proximity of pipelines and
other transportation facilities, regulation by national and local authorities
and the cost of compliance with applicable environmental regulations.
TECHNOLOGY
The Company's exploration, development and production activities depend upon
the use of applied technology. In support of this, the Company has 67 engineers,
geoscientists, technicians and support personnel focusing on the technology used
in the exploration for, and development and production of, energy resources. The
Company's expenditures on technology activities, including employee-related
costs, were $15 million, $15 million and $13 million for the years 1993, 1992
and 1991, respectively.
13
<PAGE>
THE PARTNERSHIP
Since December 1, 1985, the Company has functioned as the managing general
partner for, and has conducted its business operations in the United States
principally through the Partnership, a Delaware limited partnership. As of
December 31, 1993, the Company had a 98 percent interest in the Partnership. The
remaining two percent partnership interest is a limited partnership interest and
is held by public unitholders in the form of depositary units. There were
7,543,100 depositary units outstanding at December 31, 1993.
The Partnership operates through Sun Operating Limited Partnership, which is
a Delaware limited partnership, and several other operating partnerships.
Certain conflicts of interest may arise as a result of the relationships
between the Company and the Partnership. The directors and officers of the
Company have fiduciary duties to manage the Company in the best interest of its
stockholders. The Company, as managing general partner of the Partnership, has a
fiduciary duty to manage the Partnership in a manner that is fair to the public
unitholders. The duty of the directors of the Company to its stockholders may
therefore come into conflict with the duties of the Company to the public
unitholders. The Partnership may sell limited partnership units to the Company
for the purpose of funding the Partnership's property acquisition, exploration
and development cash requirements.
The Audit Committee of the Board of Directors of the Company (Audit
Committee), none of whose members is affiliated with the Company except as
Company directors or stockholders or as holders of units, reviews policies and
procedures developed by the Company for dealing with various matters as to which
a conflict of interest may arise. The Audit Committee also monitors the
application of such policies and procedures.
EMPLOYEES
At December 31, 1993, the number of full-time active employees of the
Company was approximately 1,500.
ITEM 3. LEGAL PROCEEDINGS
Three federal securities actions were brought against the Company and
certain of its senior officers in the United States District Court for the
Northern District of Texas in 1992. These actions, now consolidated, purport to
be brought on behalf of a class of open market purchasers of the Common Stock
during the period October 3, 1991, through June 4, 1992. The plaintiffs allege
that the Company made false and misleading statements about its financial
prospects and, in particular, about its intentions to continue paying dividends
at the same level as in the past. Plaintiffs claim violations of Section 10(b)
of the Securities Exchange Act of 1934 and related provisions. The consolidated
complaint seeks damages for alleged market losses in an unquantified amount. The
Company filed a motion to dismiss the complaint in December 1992, and plaintiffs
filed a motion for class certification in March 1993. The Court heard argument
on both motions in August 1993, but has not ruled on either motion. Management
believes that the claims have no merit and will defend against them vigorously.
The Company is involved in a number of legal and administrative proceedings
arising in the ordinary course of its oil and gas business. Although the
ultimate outcome of these proceedings cannot be ascertained at this time, it is
reasonably possible that some of the proceedings could be resolved unfavorably
to the Company. Management of the Company believes that any liabilities which
may arise would not be material in relation to its financial position at
December 31, 1993. The Company intends to maintain liability and other insurance
of the type customary in the oil and gas business with such coverage limits as
the Company deems prudent.
14
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SHAREHOLDERS
On May 6, 1993, the Annual Meeting of Shareholders of Oryx Energy Company
was held to vote on proposals as follows:
(a) To elect three directors to Class II of the Company's Board of
Directors.
<TABLE>
<CAPTION>
ROBERT L. PAUL R.
KEISER SEEGERS IAN L. WHITE-THOMSON
--------------- -------------- --------------------
<S> <C> <C> <C>
Affirmative........................... 73,277,511 73,246,029 73,265,182
Negative.............................. -- -- --
Abstained............................. -- -- --
Withheld.............................. 4,060,642 4,092,124 4,072,971
Broker non-votes...................... -- -- --
Shares without executed proxies and
not present for vote................. 19,594,124 19,594,124 19,594,124
--------------- -------------- -----------
Shares entitled to vote............... 96,932,277 96,932,277 96,932,277
--------------- -------------- -----------
--------------- -------------- -----------
</TABLE>
(b) To approve the appointment of Coopers & Lybrand as independent certified
public accountants for the fiscal year 1993.
<TABLE>
<S> <C>
Affirmative............................................................ 73,834,078
Negative............................................................... 3,094,144
Abstained.............................................................. 409,931
Withheld............................................................... --
Broker non-votes....................................................... --
Shares without executed proxies and not present for vote............... 19,594,124
----------
Shares entitled to vote................................................ 96,932,277
----------
----------
</TABLE>
EXECUTIVE OFFICERS
The following table sets forth information as to the Company's executive
officers. All officers of the Company hold their offices at the pleasure of the
Board of Directors.
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE
POSITION WITH THE COMPANY DURING PAST FIVE YEARS
- --------------------------------------------------- ------------------------------------------------------------
<S> <C>
Jerry W. Box, 55 .................................. Mr. Box has been in this position since January 1992. From
Senior Vice President, Exploration and 1987 to 1991, he was Vice President, Exploration.
Production
David F. Chavenson, 41 ............................ Mr. Chavenson assumed this position on October 1, 1993. For
Treasurer the five years previous thereto, he was Assistant Treasurer
and Manager, Corporate Finance and Credit of the Company.
Sherri T. Durst, 44 .............................. Ms. Durst assumed this position on December 2, 1993. From
General Auditor February 1990 to December 1993, she served as Manager,
Financial Processes. For the six years previous thereto,
she held the position of Financial Systems Project Manager.
Robert P. Hauptfuhrer, 62 ......................... Mr. Hauptfuhrer assumed this position on July 21, 1988,
Chairman of the Board, and Chief having been President and Chief Operating Officer of Sun
Executive Officer Company, Inc. since January 1987. From 1984 to 1987, he
served as President of the Company and Group Vice
President, Exploration and Production of Sun Company, Inc.
</TABLE>
15
<PAGE>
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE
POSITION WITH THE COMPANY DURING PAST FIVE YEARS
- --------------------------------------------------- ------------------------------------------------------------
<S> <C>
Robert L. Keiser, 51 .............................. Mr. Keiser has been in this position since January 1, 1992.
President, Chief Operating Officer and From January 1, 1990 through December 1991, he was
Director President and Chief Executive Officer of Oryx U.K. Energy
Company. He was also Vice President, International
Exploration and Production for the Company from January
1990 until August 1990 and from April 1991 through December
1991. From July 1987 to December 1989, he was Vice
President, Planning and Development of the Company. From
1986 to 1987, he was Operations Manager, International
Exploration and Production of the Company. Prior to that
time, he was Region Production Manager of the Company. From
July 1988 to November 1988, he was a Director of the
Company.
Thomas W. Lynch, 64 ............................... Mr. Lynch has been a Vice President for the past five years.
Vice President and General Counsel He has been General Counsel since November 1, 1988 and,
previous thereto, he was Chief Counsel of the Company.
Edward W. Moneypenny, 52 .......................... Mr. Moneypenny has been in this position since January 1992.
Senior Vice President, Finance, and From 1988 to 1991, he was Vice President, Finance and Chief
Chief Financial Officer Financial Officer of the Company. From 1983 to 1988, he was
also Treasurer of the Company.
William P. Stokes, Jr., 52 ........................ Mr. Stokes assumed this position on January 10, 1993. From
Vice President, Corporate Development January 1990 to January 1993, he served the Company as Vice
and Human Relations President, Planning and Development. For the five years
previous thereto, Mr. Stokes held the position of Manager
Western Production Region of the Company.
Barry L. Strong, 49 ............................... Mr. Strong has been in this position for the past five
Comptroller years.
Frank B. Sweeney, 55 .............................. Mr. Sweeney assumed this position on July 31, 1988. For the
Corporate Secretary four years previous thereto, he served the Company as Chief
Counsel and, at various times, he served as Assistant
Secretary for the Company and its subsidiaries.
William F. Whitsitt, 49 ........................... Mr. Whitsitt assumed this position on January 10, 1993. From
Vice President, Marketing November 1988 to January 1993, he served the Company as
and Public Affairs Vice President, Government Relations. From 1981 to 1988, he
served as Director, Legislative Affairs for Sun Company,
Inc.
</TABLE>
16
<PAGE>
PART II
ITEM 5. MARKET FOR ORYX ENERGY COMPANY COMMON STOCK AND
RELATED SECURITY HOLDER MATTERS
The common stock, $1 par value, of the Company (Common Stock) trades on the
New York Stock Exchange under the symbol "ORX". The following table sets forth
the high and low sales prices per share of Common Stock, as reported on the New
York Stock Exchange Composite Transactions quotations, and the dividends paid
per share of Common Stock for the periods indicated:
<TABLE>
<CAPTION>
HIGH LOW DIVIDENDS
------- ------- ----
<S> <C> <C> <C>
1993:
First quarter......................... $24 $17 1/4 $ .10
Second quarter........................ $24 7/8 $20 $ .10
Third quarter......................... $24 3/4 $19 3/8 $ .10
Fourth quarter........................ $26 1/4 $16 1/4 $ .10
1992:
First quarter......................... $27 1/4 $17 5/8 $ .30
Second quarter........................ $24 3/4 $16 3/4 $ .30
Third quarter......................... $26 5/8 $17 1/8 $ .10
Fourth quarter........................ $24 5/8 $18 5/8 $ .10
</TABLE>
The Company had 40,967 holders of record of Common Stock as of February 28,
1994.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
----------------------------------------------
1993 1992 1991 1990 1989
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
(MILLIONS OF DOLLARS, EXCEPT PER SHARE
AMOUNTS)
For the Period
Revenues............................................................ $1,054 $1,392 $1,598 $2,121 $1,208
Income (loss) before extraordinary item and cumulative effect of
changes in accounting principles (1)............................... $ (93) $ 73 $ 19 $ 225 $ 54
Net income (loss) (1)............................................... $ (100) $ 14 $ 19 $ 225 $ 139
Income (loss) per share of common stock before extraordinary item
and cumulative effect of changes in accounting principles (1)...... $(1.01) $ .74 $ .08 $ 2.26 $ .51
Net income (loss) per share of common stock (1)..................... $(1.08) $ .06 $ .08 $ 2.26 $ 1.32
Cash dividends per share of common stock (2)........................ $ .40 $ .80 $ 1.20 $ 1.20 $ 1.20
Cash dividends per share of preferred stock (3)..................... $ .725 $ 1.25 $ 1.80 $ .95
ED&A outlays (4).................................................... $ 451 $ 390 $ 569 $1,666 $ 479
At End of Period
Total assets........................................................ $3,624 $3,738 $4,257 $5,129 $4,185
Total debt (5 and 6)................................................ $1,769 $1,707 $2,362 $2,921 $1,516
Shareholders' equity (6)............................................ $ 676 $ 817 $ 534 $ 622 $1,485
<FN>
- ------------------------
(1) Net loss for 1993 includes $5 million of after-tax losses on asset
disposals and a $7 million extraordinary loss net of associated taxes from
the repurchase of indebtedness (see Note 9 to the Consolidated Financial
Statements). Net income for 1992 includes $19 million of after-tax gains
on asset disposals and a $9 million after-tax charge for costs associated
with the Company's cost restructuring program (see Note 4 to the
Consolidated Financial Statements). Net income for 1991 includes $39
million of after-tax gains on asset disposals, a $35 million after-tax
charge for costs associated with the Company's cost restructuring program
and a $25 million deferred tax
</TABLE>
17
<PAGE>
<TABLE>
<S> <C>
benefit associated with a United Kingdom tax rate reduction (see Notes 4
and 5 to the Consolidated Financial Statements). Net income for 1989
includes the recognition of an $85 million after-tax cumulative benefit
from changes made in the methods of accounting for deferred income taxes
and capitalized interest costs.
(2) In June 1992, the Company announced the reduction of the quarterly cash
dividend on its $1.00 par value common stock (Common Stock) from $.30 to
$.10 per share. In January 1994, the Company announced the suspension of
its quarterly cash dividend of $.10 per share.
(3) On September 11, 1990, the Company issued 7,259,394 shares of Series B
Junior Cumulative Convertible Preference Stock.
(4) Exploration, development and acquisition outlays (ED&A outlays) exclude
capitalized interest of $46 million, $43 million, $26 million, $13 million
and $13 million for 1993, 1992, 1991, 1990 and 1989. ED&A outlays for 1990
include the costs associated with the Company's January 1, 1990 foreign
properties acquisition.
(5) Total debt includes long-term debt of $1,741 million, $1,489 million,
$2,341 million, $2,267 million and $1,509 million at December 31, 1993,
1992, 1991, 1990 and 1989.
(6) Shareholders' equity at December 31, 1993 and 1992 includes the effects of
the sale of 17,250,000 shares of Common Stock in August 1992. Net proceeds
from the sale were used to reduce outstanding indebtedness of the Company.
Shareholders' equity at December 31, 1993, 1992, 1991 and 1990 includes
the effects of the repurchase of shares of Common Stock in September 1990.
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Management's discussion and analysis of the Company's financial position and
results of operations follows. This discussion should be read in conjunction
with the Consolidated Financial Statements and Selected Financial Data included
in this report.
BUSINESS CLIMATE
The Company has an evenly balanced portfolio of oil and gas production. The
fundamentals in the U.S. natural gas market are better today than they have been
since the mid-1980's. Excess deliverability is no longer a problem due to solid
growth in demand and reduced supply, although oil prices have constrained the
upward movement of gas prices. The Company's realized U.S. gas price in 1993 was
$1.96 per mcf or 14 percent higher than the $1.72 per mcf realized in 1992.
The fundamentals in worldwide oil markets continue to reflect an excess of
supply over demand. OPEC members have not restrained their production in a weak
global economy and prices have fallen to five-year lows. The Company's realized
oil price fell by $2.69 per barrel to $16.08 per barrel, or 14 percent less than
the 1992 price. The worldwide crude price in the fourth quarter of 1993 was
$6.20 per barrel lower than the fourth quarter of 1992. Prices in early 1994
have not shown any significant improvement from levels realized in late 1993.
The two highest priorities for the Company are to increase its production
volumes and to preserve its financial strength. These are particularly important
in times of low prices. The Company's spending is constrained by internally
generated cash flow.
LIQUIDITY AND CAPITAL RESOURCES
ED&A OUTLAYS. Total ED&A outlays differ from capital expenditures in that
they exclude capitalized interest but include cash exploration costs. ED&A
outlays were $451 million in 1993, compared to $390 million in 1992 and $569
million in 1991. In 1994, total ED&A outlays are expected to be $370 million of
which 70 percent has been earmarked for development, primarily of fields where
18
<PAGE>
increases in production volumes can be expected in the near term. Finding,
development and acquisition costs per eb were $5.53 in 1993 compared to $4.21 in
1992 and $5.21 in 1991. The average FD&A cost for the five years 1989 through
1993 was $4.64 per eb. The Company replaced 103-percent of its production in
1993, bringing its five-year average to 154-percent.
Capital expenditures in 1993 included $33 million to acquire an additional
8.2-percent interest in Ninian located in the U.K. sector of the North Sea. The
purchase cost is included in Deferred Credits and Other Liabilities. See Note 16
to the Consolidated Financial Statements.
The Company's spending levels are constrained by cash flow from operating
activities which will continue to be affected by prevailing oil and gas prices,
cost levels and production volumes. The Company is basing its 1994 spending
plans on spot oil and gas prices averaging $16.50 per barrel (WTI) and $1.94 per
mmbtu.
CASH FLOW. In 1993, the Company generated net cash flow from operating
activities of $379 million, including $28 million of proceeds from certain
interest rate hedging arrangements. In 1993, the Company generated net proceeds
from divestments of $46 million, as compared to $272 million in 1992 and $484
million in 1991. The Company's divestment plan was substantially completed in
1992.
In the fourth quarter of 1993, the Company's $200 million of 9.85-percent
notes matured and were refinanced with commercial paper and debt securities
issued under the Company's medium-term note program. Medium-term notes were also
used to repurchase approximately $78 million principal amount of its
10 3/8-percent debentures. The Company incurred a $7 million extraordinary loss
associated with the early retirement of the debentures; however, due to the
lower interest rates on the medium-term notes, this cost will be recovered in
approximately two years.
In 1992, the amount of our quarterly dividend on common stock was reduced
from $.30 per share to $.10 per share. In 1994, the Board of Directors suspended
the payment of dividends on common stock.
The Company's total debt was $1,769 million at December 31, 1993, compared
to $1,707 million at December 31, 1992. The Company expects its debt obligations
at the end of 1994 to be about the same level as the end of 1993.
GENERAL. Cash was $10 million at the end of 1993 and 1992. As a result of
the debt reduction program and refinancing activities, we have been able to
reduce the amount of our revolving credit facility from $1.1 billion at the end
of 1991 to $620 million in 1992 and 1993. The Company's current borrowing
capacity is more than adequate to meet its needs under existing economic
conditions. Moreover, the revolving credit facility is available to support the
outstanding commercial paper program, potential refinancing needs and general
liquidity.
In January 1994, Standard & Poor's (S&P) announced that it had placed the
credit ratings of the Company and seven other oil and gas companies on
"CreditWatch" with negative implications due to the "sharp decline in oil prices
since the latter part of 1993." The holders of the Company's senior ESOP notes
($102 million outstanding at December 31, 1993) would have the right, in the
event of a downgrade by S&P, to require the Company to repay the senior ESOP
notes in full at par plus a makewhole premium which at December 31, 1993 would
have been $33 million. Should such a put occur, the Company has sufficient
availability under the revolving credit facility to refinance the senior ESOP
notes.
Any shortfall in the Company's expected cash flow from operating activities
may require that it adjust its business plans. Among its options, it can defer
discretionary ED&A outlays, draw against the unused portion of its revolving
credit facility, seek additional bank borrowings or seek access to capital
markets. Its ability to incur additional indebtedness as well as its long-term
cash generation capability is ultimately tied to the value of its proved reserve
base.
19
<PAGE>
FINANCIAL PERFORMANCE
In 1991, net income fell to $19 million, a decrease of $206 million from
1990, primarily due to the impact of asset disposals on oil and gas volumes as
well as lower prices. Results for 1991 include a net restructuring charge of $35
million, a $25 million tax benefit resulting from a decrease in the U.K.
corporate tax rate and a comparative decrease in net gains from asset sales of
$14 million.
Net income for 1992 was $14 million, including $19 million from asset
disposals and a restructuring charge of $9 million. Excluding special charges,
total costs and expenses fell by $263 million, or 17 percent. However, this was
largely offset by the impacts of lower production volumes and lower oil prices.
Relative to 1991, volumes fell by about 10 percent due to asset sales and normal
declines. Oil prices were more than $2.00 per barrel lower than 1991 levels,
while U.S. natural gas prices were higher by about $.17 per mcf. The sale of
substantially all of its gas processing business in 1992 negatively affected
subsequent plant margins. In 1992, the Company also recorded a $9 million net
restructuring charge for the estimated cost of further workforce reductions.
The net loss for 1993 was $100 million which included tax-related charges of
$16 million due to the recognition of a higher U.S. corporate income tax rate,
$5 million of losses on asset disposals and a $7 million extraordinary loss
related to early debt retirement. Production volumes fell by 10-percent due
primarily to asset sales, production shortfalls and normal declines. The
Company's hedging activities decreased the overall price it received by $.28 per
barrel of oil and $.08 per mcf of gas in 1993 and by $.03 per barrel and $.02
per mcf in 1992. Total costs and expenses decreased $157 million or 12 percent
to $1,162 million in 1993 from $1,319 million in 1992, excluding the provisions
for restructuring and relinquishment of non-producing properties. The Company is
continuing to review its cost structure in an effort to further reduce costs at
all levels.
INCOME TAXES
Oryx Energy adopted SFAS No. 109, "Accounting for Income Taxes," effective
January 1, 1992. The overall effect for 1992 was zero and for 1993 was a benefit
of $5 million. As a result of applying the provisions of SFAS No. 109, a
non-cash charge or credit is included in business results based on the change in
foreign exchange rates and the corresponding impact on the deferred tax
liability. We believe these items tend to distort current period business
results and should be disregarded in analyzing its current business.
POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS
Oryx Energy adopted SFAS No. 106, "Accounting for Postretirement Benefits,"
effective January 1, 1993, and began accruing the cost of postretirement
benefits other than pensions. The after-tax impact of $59 million is being
amortized over a twenty-year period. The increase in annual expense for
providing these benefits was $4 million after the effect of income taxes.
However, cash outflows are unaffected by the adoption of SFAS No. 106.
Oryx Energy also adopted SFAS No. 112, "Employer's Accounting for
Postemployment Benefits," effective January 1, 1993, and began accruing the cost
of postemployment benefits. Since the Company has previously recognized certain
costs as required by this standard, the effect of adoption in 1993 was
insignificant.
ENVIRONMENTAL
The Company's oil and gas operations are subject to stringent environmental
regulations. The Company is dedicated to the preservation of the environment and
has committed significant resources to comply with such regulations. Although it
has been named as a potentially responsible party at sites related to past
operations, the Company believes that the potential costs to it, in the
aggregate, are not material to its financial condition. However, risks of
substantial costs and liabilities are inherent in the oil and gas business.
Should other developments occur, such as increasingly strict environmental laws,
regulations and enforcement policies or claims for damages resulting from the
Company's operations, they could result in additional costs and liabilities in
the future. See Note 16 to the Consolidated Financial Statements.
20
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Report of Indepdendent Accountants......................................................................... 44
Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1993, 1992 and 1991........................................................................ 22
Consolidated Balance Sheets at December 31, 1993 and 1992................................................ 23
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1993, 1992 and 1991........................................................................ 24
Consolidated Statements of Changes in Shareholders' Equity for the
Years Ended December 31, 1993, 1992 and 1991............................................................ 25
Notes to Consolidated Financial Statements............................................................... 26
Supplementary Financial and Operating Information (Unaudited):
Oil and Gas Data......................................................................................... 45
Quarterly Financial Information.......................................................................... 50
Financial Statement Schedules:
Report of Independent Accountants........................................................................ 55
Schedule V -- Properties, Plants and Equipment........................................................... 56
Schedule VI -- Accumulated Depreciation, Depletion and
Amortization of Properties, Plants and Equipment........................................................ 57
Schedule X -- Supplementary Income Statement Information................................................. 58
</TABLE>
21
<PAGE>
ORYX ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
----------------------
1993 1992 1991
------ ------ ------
<S> <C> <C> <C>
(MILLIONS OF DOLLARS,
EXCEPT PER SHARE
AMOUNTS)
Revenues
Oil and gas............................................................................. $1,080 $1,275 $1,484
Other (Note 2).......................................................................... (26) 117 114
------ ------ ------
1,054 1,392 1,598
------ ------ ------
Costs and Expenses
Operating costs......................................................................... 345 397 413
Production taxes (Note 3)............................................................... 112 137 155
Exploration costs....................................................................... 95 112 222
Depreciation, depletion and amortization................................................ 395 409 448
General and administrative expense...................................................... 98 120 153
Interest and debt expense............................................................... 163 187 217
Interest capitalized.................................................................... (46) (43) (26)
Provision for restructuring (Note 4).................................................... -- 14 53
Provision for relinquishment of non-producing properties (Note 4)....................... -- 63 --
------ ------ ------
1,162 1,396 1,635
------ ------ ------
Loss before extraordinary item, cumulative effect of accounting change and benefit for
income taxes............................................................................. (108) (4) (37)
Benefit for income taxes.................................................................. (10) (18) (56)
Remeasurement of foreign deferred tax (Notes 1 and 5)..................................... (5) (59) --
------ ------ ------
Income (loss) before extraordinary item and cumulative effect of accounting change........ (93) 73 19
Extraordinary item (Note 9)............................................................... (7) -- --
Cumulative effect of accounting change (Note 1)........................................... -- (59) --
------ ------ ------
Net Income (Loss)......................................................................... (100) 14 19
Less Preferred Stock Dividends............................................................ 5 9 13
------ ------ ------
Net Income (Loss) Attributable to Common Stock............................................ $ (105) $ 5 $ 6
------ ------ ------
------ ------ ------
Net Income (Loss) Per Share of Common Stock (Note 6):
Before extraordinary item and cumulative effect of accounting change.................... $(1.01) $ .74 $ .08
Extraordinary item...................................................................... (.07) -- --
Cumulative effect of accounting change.................................................. -- (.68) --
------ ------ ------
Net income (loss)....................................................................... $(1.08) $ .06 $ .08
------ ------ ------
------ ------ ------
Cash Dividends Per Share of Common Stock.................................................. $ .40 $ .80 $ 1.20
------ ------ ------
------ ------ ------
Weighted Average Number of Common and Common Equivalent Shares Outstanding (Millions of
Shares) (Note 6)......................................................................... 97.1 86.4 79.8
------ ------ ------
------ ------ ------
</TABLE>
(See Accompanying Notes)
22
<PAGE>
ORYX ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1993 1992
--------- ---------
(MILLIONS OF
DOLLARS)
<S> <C> <C>
Current Assets:
Cash and cash equivalents................................................................. $ 10 $ 10
Accounts and notes receivable and other current assets.................................... 195 265
--------- ---------
Total Current Assets.................................................................. 205 275
Properties, Plants and Equipment (Note 7)................................................... 3,333 3,365
Deferred Charges and Other Assets........................................................... 86 98
--------- ---------
Total Assets.......................................................................... $ 3,624 $ 3,738
--------- ---------
--------- ---------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................................................... $ 134 $ 151
Accrued liabilities (Note 8).............................................................. 162 199
Current portion of long-term debt (Note 9)................................................ 28 218
--------- ---------
Total Current Liabilities............................................................. 324 568
Long-Term Debt (Note 9)..................................................................... 1,741 1,489
Deferred Income Taxes (Note 5).............................................................. 682 706
Deferred Credits and Other Liabilities (Note 16)............................................ 201 158
Commitments and Contingent Liabilities (Note 10)
Shareholders' Equity (Note 11):
Preferred stock, $1 par value; 30,000,000 shares authorized; 7,259,394 shares of Series B
Junior Cumulative Convertible Preference Stock issued and outstanding in 1993 and 1992... 7 7
Common stock, $1 par value; 250,000,000 shares authorized; 126,703,553 shares issued in
1993 and 1992, 96,932,277 and 96,917,473 shares outstanding in 1993 and 1992............. 124 124
Additional paid-in capital................................................................ 2,204 2,205
Retained deficit.......................................................................... (155) (11)
--------- ---------
2,180 2,325
Less common stock in treasury, at cost; 26,769,400 and 26,784,204 shares in 1993 and
1992..................................................................................... (1,402) (1,403)
Less loan to ESOP......................................................................... (102) (105)
--------- ---------
Shareholders' Equity........................................................................ 676 817
--------- ---------
Total Liabilities and Shareholders' Equity............................................ $ 3,624 $ 3,738
--------- ---------
--------- ---------
</TABLE>
The successful efforts method of accounting is followed.
(See Accompanying Notes)
23
<PAGE>
ORYX ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Cash and Cash Equivalents From Operating Activities:
Net Income (Loss)................................................................. $ (100) $ 14 $ 19
Adjustments to reconcile net income (loss) to net cash from operating
activities:
Depreciation, depletion and amortization...................................... 395 409 448
Dry hole costs and leasehold impairment....................................... 45 56 132
Deferred income taxes......................................................... 15 10 (40)
(Gain) loss on sale of assets, net of taxes................................... 5 (59) (39)
Provision for restructuring, net of taxes..................................... -- 9 35
Extraordinary loss from debt repurchases...................................... 7 -- --
Provision for relinquishment of non-producing properties...................... -- 63 --
Proceeds from interest rate hedging activities................................ 28 9 --
Other......................................................................... 30 29 24
--------- --------- ---------
425 540 579
Changes in working capital:
Accounts and notes receivable and other current assets...................... 37 104 210
Accounts payable............................................................ (17) (55) (72)
Accrued liabilities......................................................... (66) (67) (130)
--------- --------- ---------
Net Cash Flow Provided From Operating Activities.................................. 379 522 587
--------- --------- ---------
Cash and Cash Equivalents From Investing Activities:
Capital expenditures (includes capitalized interest)............................ (453) (372) (527)
Proceeds from divestments, net of current taxes................................. 46 272 484
Other........................................................................... 20 (34) (34)
--------- --------- ---------
Net Cash Flow Used For Investing Activities....................................... (387) (134) (77)
--------- --------- ---------
Cash and Cash Equivalents From Financing Activities:
Proceeds from borrowings........................................................ 359 205 542
Repayments of long-term debt.................................................... (307) (860) (1,015)
Issuance of common stock........................................................ -- 344 --
Cash dividends paid on common and preferred stock............................... (44) (77) (108)
--------- --------- ---------
Net Cash Flow Provided From (Used For) Financing Activities....................... 8 (388) (581)
--------- --------- ---------
Changes in Cash and Cash Equivalents.............................................. -- -- (71)
Cash and Cash Equivalents at Beginning of Year.................................... 10 10 81
--------- --------- ---------
Cash and Cash Equivalents at End of Year.......................................... $ 10 $ 10 $ 10
--------- --------- ---------
--------- --------- ---------
</TABLE>
(See Accompanying Notes)
24
<PAGE>
ORYX ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
COMMON STOCK PREFERRED STOCK COMMON STOCK HELD
---------------- ---------------- ADDITIONAL RETAINED IN TREASURY LOAN
NUMBER OF PAR NUMBER OF PAR PAID-IN EARNINGS ----------------- TO
SHARES VALUE SHARES VALUE CAPITAL (DEFICIT) SHARES COST ESOP
--------- ----- --------- ----- ---------- -------- -------- ------- -----
(MILLIONS OF DOLLARS, THOUSANDS OF SHARES)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
At December 31, 1990............... 106,452 $ 106 7,259 $ 7 $ 1,879 $ 141 (26,797) $(1,403) $(108)
Net income....................... 19
Issuances from treasury.......... -- 12 --
Cash dividends declared:
Common -- $1.20 per share...... (95)
Preferred -- $1.80 per share... (13)
Repayment of loan to ESOP........ 1
--------- ----- --------- ----- ---------- -------- -------- ------- -----
At December 31, 1991............... 106,452 106 7,259 7 1,879 52 (26,785) (1,403) (107)
Net income....................... 14
Issuance of common stock......... 17,250 18 326
Issuance from treasury........... -- 1 --
Cash dividends declared:
Common -- $.80 per share....... (68)
Preferred -- $1.25 per share... (9)
Repayment of loan to ESOP........ 2
--------- ----- --------- ----- ---------- -------- -------- ------- -----
At December 31, 1992............... 123,702 124 7,259 7 2,205 (11) (26,784) (1,403) (105)
Net loss......................... (100)
Issuance from treasury........... (1) 15 1
Cash dividends declared:
Common -- $.40 per share....... (39)
Preferred -- $.725 per share... (5)
Repayment of loan to ESOP........ 3
--------- ----- --------- ----- ---------- -------- -------- ------- -----
At December 31, 1993............... 123,702 $ 124 7,259 $ 7 $ 2,204 $ (155) (26,769) $(1,402) $(102)
--------- ----- --------- ----- ---------- -------- -------- ------- -----
--------- ----- --------- ----- ---------- -------- -------- ------- -----
</TABLE>
(See Accompanying Notes)
25
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Oryx Energy Company (together with its consolidated subsidiaries, unless the
context otherwise requires, Company) was incorporated in Delaware in 1971 and
became an independent, publicly traded company on November 1, 1988. The
Company's business operations consist of the exploration and development of oil
and natural gas reserves. Since December 1, 1985, the Company has functioned as
the managing general partner for and has conducted its United States operations
through Sun Energy Partners, L.P. The Company's principal operations located
outside of the United States were acquired effective January 1, 1990 and are
identified herein by the separate geographic areas of the United Kingdom,
Indonesia and Other Foreign.
The consolidated financial statements contain the accounts of the Company
after elimination of intercompany balances and transactions. The Company's
interests in Sun Energy Partners, L.P. and its related operating partnerships
(Partnership) are fully consolidated.
CASH AND CASH EQUIVALENTS
The Company considers highly liquid investments with original maturities of
less than three months to be cash equivalents. Cash equivalents are stated at
cost which approximates market value.
PROPERTIES, PLANTS AND EQUIPMENT
The successful efforts method of accounting is followed for costs incurred
in oil and gas operations.
CAPITALIZATION POLICY -- Acquisition costs are capitalized when incurred.
Costs of unproved properties are transferred to proved properties when proved
reserves are added. Exploration costs, including geological and geophysical
costs and costs of carrying unproved properties, are charged against income as
incurred. Exploratory drilling costs are capitalized initially; however, if it
is determined that an exploratory well did not find proved reserves, such
capitalized costs are charged to expense, as dry hole costs, at that time.
Development costs are capitalized. Costs incurred to operate and maintain wells
and equipment are expensed.
LEASEHOLD IMPAIRMENT AND DEPRECIATION, DEPLETION AND AMORTIZATION --
Periodic valuation provisions for impairment of capitalized costs of unproved
properties are expensed.
The acquisition costs of proved properties are depleted by the
unit-of-production method based on proved reserves by field. Capitalized
exploratory drilling costs which result in the addition of proved reserves and
development costs are amortized by the unit-of-production method based on proved
developed reserves by field.
DISMANTLEMENT, RESTORATION AND ABANDONMENT COSTS -- Estimated costs of
future dismantlement, restoration and abandonment are accrued as a component of
depreciation, depletion and amortization expense; actual costs are charged to
the accrual.
RETIREMENTS -- Gains and losses on the disposals of fixed assets are
generally reflected in income. For certain property groups, the cost less
salvage value of property sold or abandoned is charged to accumulated
depreciation, depletion and amortization except that gains and losses for these
groups are taken into income for unusual retirements or retirements involving an
entire property group.
CAPITALIZED INTEREST
The Company capitalizes interest costs incurred as a result of the
acquisition and installation of significant assets.
26
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
INCOME TAXES
In February 1992, Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes" was issued and it required the adoption of
its provisions no later than January 1, 1993. During the fourth quarter of 1992,
the Company adopted the provisions of SFAS No. 109 retroactive to January 1,
1992. The effect to the Company of adopting SFAS No. 109 was to increase, as of
January 1, 1992, deferred foreign income tax liabilities, which resulted in a
$59 million ($.68 per share) cumulative charge (Cumulative Charge) to 1992
earnings. This increase in the Company's deferred foreign income tax liabilities
results from the remeasurement of the Company's foreign currency denominated
deferred tax liabilities at current exchange rates. The remeasurement provisions
of SFAS No. 109 also affect the reported earnings of the Company for 1993 and
1992. Earnings for 1993 were increased by $5 million from remeasuring the
Company's foreign deferred tax liabilities under SFAS No. 109. Earnings for 1992
were increased by $59 million from remeasuring the Company's foreign deferred
tax liabilities. Management believes that such non-cash remeasurement credits
and debits distort current period economic results and should be disregarded in
analyzing the Company's current business. Future economic results may also be
distorted because payment of the deferred tax liability is not expected to occur
in the near-term and it is likely that exchange rates will fluctuate prior to
the eventual settlement of the liability.
PENSION AND OTHER POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS
The Company has established noncontributory defined benefit plans and
defined contribution plans to provide retirement benefits for most of its
employees. Pension benefits are charged against earnings of the Company over the
periods in which they are earned by the employees (Note 12).
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees and certain
insurance and other postemployment benefits for individuals whose employment is
terminated by the Company prior to their normal retirement. Substantially all of
the Company's employees may become eligible for postretirement benefits if they
reach normal retirement age while working for the Company. Historically, the
cost of retiree health care and life insurance benefits and certain
postemployment benefits have been recognized as expenses as such claims or costs
were paid. In December 1990, SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions", was issued and it requires
companies to recognize the costs of postretirement benefits other than pensions
on an accrual basis. The Company adopted SFAS No. 106 on January 1, 1993, and
began accruing the cost of postretirement benefits other than pensions. The
related transition obligation of $59 million after-tax is being amortized to
expense over a twenty year period. The increase in annual expense for providing
these benefits was $4 million after the effect of income taxes. However, cash
outflows are unaffected by the adoption of SFAS No. 106.
In November 1992, SFAS No. 112, "Employers' Accounting for Postemployment
Benefits", was issued. It requires companies to recognize the costs of
postemployment benefits on an accrual basis. The Company adopted SFAS No. 112 on
January 1, 1993, and began accruing the cost of postemployment benefits. Since
the Company had previously recognized certain costs as required by this
standard, the effect of adoption was insignificant.
SALES OF OIL AND GAS
Sales of oil and gas are recorded on the entitlement method. Differences
between actual production and entitlements result in amounts due when
underproduction occurs and amounts owed when overproduction occurs.
27
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
FOREIGN CURRENCY TRANSLATION
The United States dollar is the functional currency for the Company's
consolidated foreign operations. For those operations, all transaction gains or
losses from currency fluctuations are included in income currently.
FOREIGN EXCHANGE CONTRACTS
The Company enters into foreign exchange contracts to reduce the impact of
changes in exchange rates upon foreign denominated receivables and payables.
Market value gains and losses recognized offset foreign exchange gains or
losses.
At December 31, 1993 and 1992, the Company was party to contracts with
foreign currency equivalents of $49 million and $94 million. Counterparties to
these agreements are major financial institutions. The Company believes that
losses from nonperformance by the counterparties are unlikely to occur.
INTEREST RATE FUTURES AGREEMENTS
The Company has entered into interest rate hedging arrangements to
effectively alter the floating rate portion of its underlying debt portfolio.
The differentials to be paid or received under such agreements are accrued as
interest rates change and are recorded as increments or offsets to interest and
debt expense. Proceeds received from certain agreements are amortized over the
life of the agreements as an offset to interest and debt expense.
At December 31, 1993, the Company had outstanding $100 million of interest
rate caps maturing in 1997 and $250 million maturing in 1998. Under the terms of
the caps, the Company must pay the counterparty the excess, if any, by which
LIBOR (3.5 percent at December 31, 1993) exceeds 5 percent. The Company also
sold to counterparties an option to exercise a $250 million interest rate swap
on August 15, 1995. If exercised, the Company must pay 9.75 percent and receive
LIBOR for a three year period commencing September 1995. At December 31, 1992,
the Company was party to interest rate hedging arrangements with notional
amounts of $400 million. Counterparties to these agreements are major financial
institutions. The Company believes that losses from nonperformance by the
counterparties are unlikely to occur.
FUTURES TRADING ACTIVITY
The Company, from time to time, enters into futures contracts to hedge the
impact of price fluctuations on crude and natural gas production. Futures
trading activity decreased oil and gas revenue by $29 million in 1993 and $7
million in 1992. At December 31, 1993 the Company had hedged about 30 percent of
its 1994 U.S. gas production at an average floor of $2.04 per mmbtu and an
average ceiling of $2.28 per mmbtu.
FINANCIAL INSTRUMENTS
The difference between the values calculated as prescribed by SFAS No. 107,
"Disclosures about Fair Value of Financial Instruments", of the Company's
financial instruments and their carrying value is not material.
ENVIRONMENTAL COSTS
The Company establishes reserves for environmental liabilities as such
liabilities are incurred (Note 16).
28
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
CEILING TESTS
For ceiling test purposes, the Company compares its worldwide undiscounted
standardized measure of future net cash flows from estimated production of
proved oil and gas reserves before income taxes to its net properties, plants
and equipment related to oil and gas operations.
STATEMENT PRESENTATION
Certain items in years prior to 1993 have been reclassified to conform to
the 1993 presentation.
(2) OTHER REVENUES
The components of other revenues were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Interest income.............................................. $ 1 $ 5 $ 5
Gas plant margins*........................................... 6 34 61
Gain (loss) on sale of assets................................ (7) 94 61
Miscellaneous................................................ (26) (16) (13)
--------- --------- ---------
$ (26) $ 117 $ 114
--------- --------- ---------
--------- --------- ---------
<FN>
- ------------------------
*Associated with the restructuring announced in 1991, the Company sold
substantially all of its gas plant business in 1992. After-tax cash flows from
the Company's gas plant business amounted to $4 million, $22 million and $39
million in 1993, 1992 and 1991 (Note 4).
</TABLE>
(3) PRODUCTION TAXES
Production taxes consisted of the following:
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Royalties.................................................... $ 60 $ 75 $ 103
Severance.................................................... 35 43 40
Property taxes............................................... 17 19 15
Petroleum revenue taxes...................................... -- -- (3)
--------- --------- ---------
$ 112 $ 137 $ 155
--------- --------- ---------
--------- --------- ---------
</TABLE>
(4) CHANGES IN BUSINESS
Effective January 31, 1991, the Company sold its interests in the
Midway-Sunset Field producing oil and gas assets and a steam cogeneration
facility. Net proceeds of $534 million from the sale, including $54 million of
debt assumed by the purchaser, were used to reduce the Company's debt in 1991.
In 1991, the Company commenced a major restructuring program designed to
accelerate the implementation of its key operating strategies and reduce its
debt and cost structure. The program outlined a plan to reduce debt by selling
substantially all of the Company's gas plant business and certain producing oil
and gas properties located primarily in the onshore U.S.
Additionally, in 1992 the Company relinquished $63 million of U.S.
non-producing properties which generated a $31 million tax benefit. Overall,
asset disposals in 1992 generated an after-tax gain of $19 million to the
Company. As of December 31, 1992, the Company had completed asset disposals
which generated $342 million in net proceeds. At December 31, 1992, the asset
disposal program was
29
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) CHANGES IN BUSINESS (CONTINUED)
substantially complete although from time to time the Company will have
divestments. In 1993, the Company completed asset disposals that generated $46
million in net proceeds and generated an after-tax loss of $5 million.
Associated with the restructuring, the Company recognized a $53 million
pretax ($35 million after-tax) provision in 1991. An additional $14 million
pretax ($9 million after-tax) provision for restructuring was recognized in
1992, together with a $63 million pretax ($41 million after-tax) provision for
the early relinquishment of certain U.S. non-producing properties.
(5) INCOME TAXES
Loss before extraordinary item and benefit for income taxes consisted of the
following:
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
United States loss......................................... $ (93) $ (29) $ (63)
Foreign income (loss)...................................... (15) 25 26
--------- --------- ---------
$ (108) $ (4) $ (37)
--------- --------- ---------
--------- --------- ---------
</TABLE>
The benefit for income taxes for each of the years 1993, 1992 and 1991 is
applicable to continuing operations.
The components of the benefit for income taxes on loss before extraordinary
item and accounting changes were as follows:
<TABLE>
<CAPTION>
1993 1992* 1991
--------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Federal:
Current tax provision (benefit)............................ $ (17) $ 42 $ 64
Deferred tax provision (benefit)........................... 4** (57) (106)
Foreign:
Current tax provision...................................... 8 18 6
Deferred tax benefit....................................... (5) (21) (20)***
--- --- ---------
$ (10) $ (18) $ (56)
--- --- ---------
--- --- ---------
<FN>
- ------------------------
*Effective January 1, 1992, the Company adopted SFAS No. 109.
**Includes a $17 million deferred tax provision associated with a U.S. tax rate
increase.
***Includes a $25 million deferred tax benefit associated with a U.K. tax rate
reduction.
</TABLE>
At December 31, 1993, the Company had Alternative Minimum Tax (AMT) credit
carryforwards of approximately $30 million and other deferred tax assets of
approximately $77 million.
The types of differences between the tax bases of assets and liabilities and
their financial reporting amounts that give rise to significant portions of
deferred income tax liabilities and assets were: valuation and amortization of
properties, plants and equipment; provision for write-down of assets; accrual of
employee terminations, office closings and other matters; and tax net operating
loss carryforwards and carrybacks.
30
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(5) INCOME TAXES (CONTINUED)
Following is the reconciliation of the tax benefit calculated at the U.S.
statutory tax rate to the Company's actual tax benefit on loss before
extraordinary item and accounting changes:
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
U.S. statutory rate calculation.............................................. $ (38) $ (1) $ (13)
Increase (reduction) in taxes resulting from:
Interest allocation adjustment............................................. 5 (8) (6)
AMT credit................................................................. -- (8) --
Deferred impact of tax rate changes........................................ 17 -- (25)
Other...................................................................... 6 (1) (12)
--------- --------- ---------
Benefit for income taxes before remeasurement of foreign deferred tax........ (10) (18) (56)
Remeasurement of foreign deferred tax as required by SFAS No. 109............ (5) (59) --
--------- --------- ---------
Benefit for income taxes..................................................... $ (15) $ (77) $ (56)
--------- --------- ---------
--------- --------- ---------
</TABLE>
(6) INCOME PER SHARE
The 7,259,394 shares of Series B Preference Stock are common stock
equivalents. Conversion of the Series B Preference Stock in 1993, 1992 or 1991
would have been anti-dilutive to the Company's earnings per share. The Company
has reserved 5,111,438 shares of Common Stock for issuance to the owners of its
7 1/2% Convertible Subordinated Debentures Due 2014 (Debentures). The Debentures
are convertible into the Company's Common Stock at any time prior to maturity at
$39.125 per share of Common Stock. The Debentures are not common stock
equivalents. If conversion of the Debentures were assumed to have occurred, the
result would have been anti-dilutive to 1993, 1992 and 1991 earnings per share.
(7) PROPERTIES, PLANTS AND EQUIPMENT
At December 31, the Company's properties, plants and equipment and
accumulated depreciation, depletion and amortization were as follows:
<TABLE>
<CAPTION>
1993 1992
--------- ---------
(MILLIONS OF
DOLLARS)
<S> <C> <C>
Gross investment
Proved properties............................................ $ 6,184 $ 5,933
Unproved properties.......................................... 257 266
Other........................................................ 82 81
--------- ---------
6,523 6,280
--------- ---------
Less accumulated depreciation, depletion and amortization
Proved properties............................................ 3,138 2,865
Unproved properties.......................................... -- 2
Other........................................................ 52 48
--------- ---------
3,190 2,915
--------- ---------
Net investment................................................. $ 3,333 $ 3,365
--------- ---------
--------- ---------
</TABLE>
31
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) ACCRUED LIABILITIES
At December 31, the Company's accrued liabilities were comprised of the
following:
<TABLE>
<CAPTION>
1993 1992
--------- ---------
(MILLIONS OF
DOLLARS)
<S> <C> <C>
Drilling and operating costs.............................................. $ 89 $ 80
Restructuring reserve (Note 4)............................................ 7 30
Interest payable.......................................................... 28 34
Employee related costs and benefits....................................... 17 16
Royalties payable......................................................... 4 8
Taxes payable............................................................. (9) 19
Other..................................................................... 26 12
--------- ---------
$ 162 $ 199
--------- ---------
--------- ---------
</TABLE>
(9) LONG-TERM DEBT
At December 31, long-term debt consisted of the following (in millions of
dollars):
<TABLE>
<CAPTION>
1993 1992
--------- ---------
<S> <C> <C>
9.75% Notes Due 1998....................................................... $ 250 $ 250
10.375% Debentures payable $9 annually 1999 - 2018......................... 171 249
10% Notes Due 1999 and 2001 payable $100 in 1999 and $149 in 2001.......... 249 249
9.85% Notes Due 1993....................................................... -- 200
7.50% Convertible Subordinated Debentures payable $10 annually 1999 - 2013
and $50 in 2014........................................................... 200 200
Medium Term Notes, variable and fixed interest rates ranging from 4.50% to
9.50% at December 31, 1993 due during 1994 - 2002......................... 180 40
9.30% Notes Due 1996....................................................... 100 100
7.20% Note (to be reset in 1998) payable semi-annually 1995 - 2006*........ 100 100
9.50% Notes Due 1999....................................................... 100 99
8.35% to 8.70% Senior ESOP Notes payable quarterly 1994 - 2009............. 102 105
Commercial Paper, variable interest rates ranging from 3.90% to 4.21% at
December 31, 1993**....................................................... 100 37
Variable interest rate (ranging from 3.82% to 3.964% at December 31, 1993)
revolving credit facility payable semi-annually 1996 - 1997***............ 150 40
Capitalized lease obligations and other long-term debt due 1994 - 2002..... 67 38
--------- ---------
1,769 1,707
Less: Current portion...................................................... 28 218
--------- ---------
$ 1,741 $ 1,489
--------- ---------
--------- ---------
<FN>
- ------------------------
*A consortium of banks has guaranteed the performance of one of the Company's
subsidiaries' financial obligations by issuing a letter of credit in favor of
the obligee for the outstanding loan balance plus interest and compensatory
damages. At December 31, 1993, the balance on the letter of credit was $110
million.
</TABLE>
32
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) LONG-TERM DEBT (CONTINUED)
<TABLE>
<S><C>
**Commercial paper matures from 4 to 32 days. Such debt is classified as
long-term due to management's intention to continue to use commercial paper
as a financing vehicle and the availability of credit under the Company's
revolving credit facility.
***At December 31, 1993, $25 million of variable interest rate revolving credit
facility debt has been recognized as extinguished by the Company as a result
of having funded an irrevocable trust with U.S. Treasury obligations. The
debt matured in January 1994.
</TABLE>
Long-term debt maturities are $28 million, $138 million, $266 million, $153
million and $264 million for each of the years 1994 through 1998. Each of the
maturity amounts for 1996 and 1997 include an assumed payment of $125 million
related to the revolving credit facility which Management intends to renew.
The Company's long-term debt contains restrictive covenants, including a
limitation on total indebtedness; restriction on the payment of common stock
dividends in excess of $1.20 annually and minimum cash flow interest coverage.
At December 31, 1993, the Company was in compliance with all of its debt
covenants.
The Company pays a fee ranging from .375 percent to .5 percent on the unused
portion of its $620 million revolving credit facility. As of December 31, 1993,
the Company had the capacity to borrow $281 million under such facility. The
commitments are subject to withdrawal if the Company were to be in default under
any agreement for indebtedness in excess of $25 million.
During the fourth quarter of 1993, the Company repurchased $78 million of
its 10.375 percent debentures at a total cost of $88 million resulting in an
after-tax loss of $7 million which is reflected as an extraordinary item in the
Consolidated Statement of Income.
(10) COMMITMENTS AND CONTINGENT LIABILITIES
The Company has operating leases for office space and other property and
equipment. Total rental expense for such leases for the years 1993, 1992 and
1991 was $32 million, $33 million and $38 million. Under contracts existing as
of December 31, 1993, future minimum annual rental payments applicable to
non-cancelable operating leases that have initial or remaining lease terms in
excess of one year were as follows (in millions of dollars):
<TABLE>
<S> <C>
Year ending December 31:
1994................................................ $ 26
1995................................................ 19
1996................................................ 14
1997................................................ 13
1998................................................ 13
Later years......................................... 85
---------
Total minimum payments required................... $ 170
---------
---------
</TABLE>
Under the terms of an operating lease which expires in December 1994, the
Company is obligated to pay the lessor at the expiration of the lease the
amount, if any, by which the fair market value of the asset is less than $31
million.
Several legal and administrative proceedings are pending against the
Company. Although the ultimate outcome of these proceedings cannot be
ascertained at this time, and it is reasonably possible that some of them could
be resolved unfavorably to the Company, management believes that any liabilities
which may arise would not be material in relation to the consolidated financial
position of the Company at December 31, 1993.
33
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(11) SHAREHOLDERS' EQUITY
Effective in October 1988, 3,001,876 shares of Common Stock of the Company
were issued to an operating partnership of the Partnership in exchange for
certain assets, which shares have been deducted from the number of shares shown
in the consolidated balance sheet as outstanding. Such shares are not entitled
to be voted at the annual meeting of shareholders. All other shares of Common
Stock are entitled to one vote per share.
On August 1, 1989, the Company privately placed $110 million of notes (ESOP
Notes) with maturities ranging from 15 to 20 years and interest rates currently
ranging from 8.35% to 8.70%. The ESOP Notes were issued pursuant to the
provisions of the Oryx Energy Company Capital Accumulation Plan (CAP), which is
designed to constitute an employee stock ownership plan (ESOP) within the
meaning of the Internal Revenue Code. The Company loaned the proceeds from the
issuance of the ESOP Notes to the ESOP, which used the funds to purchase Common
Stock of the Company. The ESOP is repaying the loan to the Company using the
Company's contributions to the CAP and any dividends paid on shares of Common
Stock held by the ESOP.
The Company has 280,000,000 authorized shares of stock, consisting of (i)
250,000,000 shares of Common Stock having a par value of $1.00 per share, (ii)
15,000,000 shares of Cumulative Preference Stock (Preference Stock) having a par
value of $1.00 and a liquidation preference of $.001 per share, and (iii)
15,000,000 shares of Preferred Stock (Preferred Stock) having a par value of
$1.00 per share. As of December 31, 1993, there were 96,932,277 shares of Common
Stock outstanding. There are two series of Preference Stock designated, of which
there were 7,259,394 shares of Series B Preference Stock outstanding and 120,000
shares of Series A Preference Stock designated and reserved for issuance upon
exercise of the Stock Purchase Rights (Rights), of which none were outstanding.
The Preferred Stock was authorized by vote of the shareholders on May 5, 1992
and there are currently no shares of Preferred Stock designated or outstanding.
In addition, on December 31, 1993 the Company had reserved for issuance
7,259,394 shares of Common Stock on conversion of the outstanding Series B
Preference Stock, 5,111,438 shares of Common Stock on conversion of the
outstanding 7 1/2% Convertible Debentures and 1,914,832 shares of Common Stock
upon the exercise of outstanding management options.
COMMON STOCK
Each share of Common Stock entitles its record owner to one vote on all
matters submitted to the stockholders for action. The stockholders are not
entitled to cumulative voting rights in the election of directors. Subject to
the rights of holders of any class of Preference Stock or Preferred Stock, the
holders of Common Stock are entitled to share ratably in dividends in such
amount as may be declared by the Company's Board of Directors (Board) from time
to time out of funds legally available therefor. The payment of dividends on the
Common Stock is restricted under the Credit Agreement to no more than $1.20 per
share annually, and is prohibited in the event of a default.
PREFERENCE STOCK
The Board is authorized by the Certificate to issue Preference Stock in one
or more series and to fix for each such series such qualifications, privileges,
limitations, options, conversion rights, and other special rights as are stated
and adopted by the Board and as are permitted by the Certificate and the
Delaware General Corporation Law, including the designation and number of shares
issuable, the dividend rate, voting rights, conversion rights, redemption and
sinking fund provisions, and liquidation values of each such series.
34
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(11) SHAREHOLDERS' EQUITY (CONTINUED)
Holders of Preference Stock are entitled to receive, when and as declared by
the Board out of assets legally available for that purpose, annual cumulative
dividends payable in quarterly installments. Unless full cumulative dividends on
the Preference Stock have been paid, no dividend may be declared or paid on, or
other distributions made upon, Preferred Stock or Common Stock, nor may any
Preferred Stock or Common Stock be redeemed or purchased by the Company.
Subject to certain conditions, the Company may redeem all or any part of the
Preference Stock then outstanding.
The Company had 7,259,394 shares of Series B Preference Stock outstanding at
December 31, 1993. Any such shares held by the original holder shall be entitled
to a dividend in excess of the dividend payable on Common Stock. Any periodic
dividend declared subsequent to 1993 will be increased by a dividend preference
equal to $.0625 per share with respect to the first and second succeeding
quarters and $.025 per share with respect to the third through sixth succeeding
quarters. In 1994, the Board of Directors of the Company voted to suspend the
dividend on Common Stock. Such suspension will not affect the dividend
preference on the Series B Preference Stock.
Series B Preference Stock is non-voting, except in certain cases specified
in the Certificate or by law, and it is convertible into Common Stock on a
share-for-share basis by the holder thereof subject to certain restrictions.
After September 10, 1995, if the original holder of the Series B Preference
Stock still owns it, those shares may be converted into Common Stock on a
share-for-share basis by the holder thereof without the restrictions that
applied on or before that date.
PREFERRED STOCK
The Board is authorized by the Certificate to issue Preferred Stock in one
or more series and to fix for each such series such qualifications, privileges,
limitations, options, conversion rights, and other special rights as are stated
and adopted by the Board and as are permitted by the Certificate and the
Delaware General Corporation Law, including the designation and number of shares
issuable, the dividend rate, voting rights, conversion rights, redemption and
sinking fund provisions, and liquidation values of each such series.
Subject to the rights of holders of any class of Preference Stock, if any,
the holders of Preferred Stock are entitled to receive dividends, when and as
declared by the Board out of funds legally available for that purpose. As to
dividends and rights upon liquidation, dissolution or winding up, the Preferred
Stock will rank junior and subordinate to any series of Preference Stock, and
prior to the Common Stock.
RIGHTS
On September 11, 1990, the Board declared a dividend distribution of one
Stock Purchase Right on each outstanding share of Common Stock, payable
September 28, 1990, to holders of record of the Common Stock on that date. The
Rights are also issuable upon the issuance of additional shares of Common Stock
prior to the time the Right are redeemed or expire. Initially, the Rights are
represented by the certificates for the Common Stock and will trade only with
the Common Stock. The Rights will expire September 11, 2000 unless earlier
redeemed by the Company.
(12) EMPLOYEE AND RETIREE BENEFIT PLANS
DEFINED BENEFIT PENSION PLANS
The Company has noncontributory defined benefit plans which provide
retirement benefits for most of its employees. Plan benefits are generally based
on years of service, age at retirement and the employee's compensation. It is
the Company's policy to fund defined benefit pension contributions, at a
minimum, in accordance with the requirements of the Internal Revenue Code.
35
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(12) EMPLOYEE AND RETIREE BENEFIT PLANS (CONTINUED)
The cost of the Company's primary defined benefit pension plans consisted of
the following:
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Service cost (cost of benefits earned during the year).................... $ 6 $ 8 $ 9
Interest cost on projected benefit obligation............................. 38 39 40
Actual return on plan assets*............................................. (40) (44) (43)
Net amortization and deferral*............................................ (2) (2) (3)
--- --- ---
Net periodic pension cost............................................... $ 2 $ 1 $ 3
--- --- ---
--- --- ---
<FN>
- ------------------------
*Estimated returns on assets are used in determining net periodic pension cost.
Differences between estimated and actual returns are included in net
amortization and deferral.
</TABLE>
The following table sets forth the funded status and amounts recognized in
the Company's Consolidated Balance Sheets at:
<TABLE>
<CAPTION>
DECEMBER 31, 1993 DECEMBER 31, 1992
------------------------------ ------------------------------
PLANS IN PLANS IN
PLANS IN WHICH WHICH PLANS IN WHICH WHICH
ASSETS EXCEED ACCUMULATED ASSETS EXCEED ACCUMULATED
ACCUMULATED BENEFITS ACCUMULATED BENEFITS
BENEFITS EXCEED ASSETS BENEFITS EXCEED ASSETS
--------------- ------------- --------------- -------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Actuarial present value of benefit obligation:
Vested................................................. $ 392 $ 82 $ 383 $ 80
Nonvested.............................................. 16 3 14 3
----- ----- ----- -----
Accumulated benefit obligation........................... 408 85 397 83
Effect of projected future salary increases.............. 31 2 39 3
----- ----- ----- -----
Projected benefit obligation............................. 439 87 436 86
Less plan assets at fair value*.......................... 457 -- 449 --
----- ----- ----- -----
Projected benefit obligation in excess of (less than)
plan assets............................................. (18) 87 (13) 86
Unrecognized net asset (obligation) at January 1, 1986... 38 (17) 44 (19)
Unrecognized prior service benefit (cost)................ (4) 3 (4) 3
Unrecognized net gain (loss)............................. (37) (27) (39) (24)
Additional minimum liability............................. -- 39 -- 37
----- ----- ----- -----
Accrued pension liability (asset)**...................... $ (21) $ 85 $ (12) $ 83
----- ----- ----- -----
----- ----- ----- -----
<FN>
- ------------------------
*Plan assets consist principally of commingled trust funds, marketable equity
securities, guaranteed insurance contracts, corporate and government debt
securities and real estate. At December 31, 1993, less than one percent of
plan assets was invested in Common Stock of the Company.
**Accrued pension liability is included in "Deferred Credits and Other
Liabilities" in the Consolidated Balance Sheets.
</TABLE>
36
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(12) EMPLOYEE AND RETIREE BENEFIT PLANS (CONTINUED)
As of December 31, 1993 and 1992, the projected benefit obligations were
determined using a weighted average assumed discount rate of 7 and 7.5 percent
and a rate of compensation increase of 4 and 5 percent, respectively. The
weighted average expected long-term rate of return on plan assets was 9.5
percent in 1993 and 1992. All of these rates are subject to change in the future
as economic conditions change.
DEFINED CONTRIBUTION PENSION PLANS
Defined contribution plans designed to provide retirement benefits are
available to substantially all employees. Contributions, which are principally
based on employees' compensation, are expensed as incurred.
The principal defined contribution plan is CAP which is a combined stock
bonus and leveraged ESOP and is available to substantially all U.S. employees.
The first 5 percent of employee contributions are matched by the Company at 110
percent up to the first $50,000 of employee base salary and at 100 percent
thereafter. The Company's contributions to CAP are used to repay the debt issued
to fund the purchase of Common Stock held by the leveraged ESOP. From time to
time, the Company may contribute more than the calculated matching contribution
when necessary to meet loan payments. CAP costs recognized amounted to $10
million, $9 million and $8 million for 1993, 1992 and 1991.
Additional information with respect to the leveraged ESOP portion of CAP is
as follows:
<TABLE>
<CAPTION>
1993 1992 1991
------- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Interest cost on ESOP debt................................................... $ 9 $ 9 $ 9
Company cash contributions to the ESOP....................................... $ 10 $ 8 $ 7
ESOP dividends used for debt service......................................... $ 1 $ 3 $ 3
</TABLE>
HEALTH CARE AND LIFE INSURANCE BENEFITS
The Company sponsors unfunded defined benefit health care and life insurance
benefit plans to substantially all employees and retirees. Benefits under the
health care plan are provided on a self-insured basis or through certain Health
Maintenance Organizations (HMOs). The health care plan provides comprehensive
major medical coverage which integrates with Medicare and contains provisions
for cost sharing with participants through contributions, coinsurance,
deductibles and caps on employer costs. Benefits under the life insurance plan
are provided through an insurance contract. The life insurance plan contains
provisions for retiree cost sharing through contributions and provides benefits
based on preretirement compensation with a scheduled reduction in benefits
commencing at age 66 and termination of all benefits at age 70 for substantially
all participants.
The cost of health care and life insurance benefit plans was $20 million,
$16 million and $16 million, of which $12 million, $7 million and $5 million was
for retirees in 1993, 1992 and 1991. The Company adopted SFAS No. 106 on January
1, 1993, and in accordance with its provisions has changed to the accrual
accounting method in computing postretirement health care and life insurance
benefit plan expense. The Company formerly accounted for these costs using the
pay-as-you-go (cash) method.
37
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(12) EMPLOYEE AND RETIREE BENEFIT PLANS (CONTINUED)
The cost, net of retiree contributions, of the postretirement health care
and life insurance benefit plans in 1993 calculated in accordance with the
provisions of SFAS No. 106 is as follows:
<TABLE>
<CAPTION>
1993
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Service cost (cost of benefits earned during the year)... $ 1
Interest cost on the accumulated postretirement benefit
obligation.............................................. 7
Actual return on plan assets............................. --
Amortization of transition obligation*................... 4
-----
Net periodic postretirement benefit cost................. $ 12
-----
-----
<FN>
- ------------------------
*The transition obligation is being amortized over a 20 year period.
</TABLE>
The following table sets forth the funded status and amounts reported in the
Company's Consolidated Balance Sheet at:
<TABLE>
<CAPTION>
DECEMBER 31, 1993
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Accumulated postretirement benefit obligation:
Retirees............................................... $ 83
Active employees eligible to retire.................... 4
Active employees not yet eligible to retire............ 17
-----
Total accumulated postretirement benefit obligation...... 104
Less plan assets at fair value........................... --
-----
Accumulated obligation in excess of plan assets.......... 104
Unrecognized actuarial loss.............................. (12)
Unrecognized transition obligation....................... (86)
-----
Accrued postretirement benefit liability*................ $ 6
-----
-----
<FN>
- ------------------------
*Accrued postretirement benefit liability is included in "Deferred Credits and
Other Liabilities" in the Consolidated Balance Sheet.
</TABLE>
The assumed health care cost trend rate used to measure the expected cost of
benefits covered by the plan for 1994 is 7 percent. Health care cost trend rates
for future years are assumed to gradually trend downward over a seven year
period to meet and thereafter parallel the projected rate of general inflation
of 4.5 percent. A 1 percent increase in the assumed health care cost trend rates
for future years would result in a $1 million increase in annual cost and a $9
million increase in the accumulated postretirement benefit obligation for the
Company's health care plan.
The weighted average of the assumed discount rates used to measure the
accumulated postretirement benefit obligation is 7 percent. For the life
insurance plan, an assumed rate of increase of compensation of 4 percent was
used to measure the accumulated postretirement benefit obligation.
38
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(13) MANAGEMENT INCENTIVE PLANS
The Company provides management incentive plans to certain employees in the
management of the Company. Total charges against income for these plans were $2
million, $4 million and $2 million for 1993, 1992 and 1991.
The principal management incentive plans are the 1992 Long-Term Incentive
Plan (1992 LTIP), the Long-Term Incentive Plan (LTIP) and the Executive
Long-Term Incentive Plan (ELTIP). The ELTIP provides that no awards may be
granted after November 1, 1988 and was replaced by the LTIP which provides that
no awards may be granted after December 31, 1991. All previous awards granted
under both the ELTIP and LTIP remain in effect in accordance with their terms.
As of December 31, 1993, there were no outstanding awards granted under the
ELTIP. The 1992 LTIP replaced the LTIP and became effective January 1, 1992. A
maximum of 3,000,000 shares of Common Stock were authorized for issuance under
the 1992 LTIP.
Under the provisions of these plans, stock options, stock appreciation
rights and limited rights were granted in various tandem combinations so that
the exercise of any one of them will reduce, on a one-for-one basis, the tandem
options or rights. In addition, certain stock options were granted which become
exercisable (subject to the option vesting schedule) only upon the cancellation
of the related performance shares for non-attainment of performance targets.
The following table summarizes information with respect to Common Stock
options awarded under the 1992 LTIP, the LTIP and the ELTIP:
<TABLE>
<CAPTION>
1993 1992
-------------------------- -------------------------- 1991
SHARES SHARES -----------------------------------
UNDER OPTION PRICE UNDER OPTION PRICE SHARES UNDER OPTION PRICE
OPTION PER SHARE OPTION PER SHARE OPTION PER SHARE
--------- --------------- --------- --------------- -------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding, January 1.......... 1,491,116 $ 20.36-$44.13 1,076,265 $ 20.36-$44.13 748,949 $ 20.36-$44.13
Granted*........................ 470,690 $19.63 449,900 $26.00 331,080 $36.00
Exercised**..................... -- -- (944) $20.36 (2,704) $ 24.16-$25.63
Cancelled....................... (46,974) $ 20.36-$44.13 (34,105) $ 24.16-$44.13 (1,060) $44.13
--------- --------- --------------
Outstanding, December 31........ 1,914,832 $ 19.63-$44.13 1,491,116 $ 20.36-$44.13 1,076,265 $ 20.36-$44.13
--------- --------- --------------
--------- --------- --------------
Exercisable, December 31***..... 773,256 $ 24.16-$44.13 571,390 $ 20.36-$44.13 439,310 $ 20.36-$44.13
--------- --------- --------------
--------- --------- --------------
Available for grant, December
31****......................... 1,835,440 2,411,653 1,507,495*****
--------- --------- --------------
--------- --------- --------------
<FN>
- ------------------------
*Includes 209,300; 196,340 and 136,270 stock options granted in tandem with
performance shares in 1993, 1992 and 1991 which become exercisable only
upon cancellation of the related performance shares.
**Includes 254 options cancelled in 1991 due to the exercise of the related
stock appreciation rights, all of which were settled for cash.
***Excludes outstanding stock options granted in tandem with performance
shares in 1993, 1992 and 1991 which become exercisable (subject to the
option vesting schedule) only upon cancellation of the related performance
shares. In January 1994, 95,289 such stock options granted in 1991 became
exercisable due to the cancellation of the related performance shares.
****Shares available for grant is net of the number of performance shares
outstanding which were granted under the provisions of these plans.
*****No awards may be granted under the LTIP after December 31, 1991.
</TABLE>
39
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(14) GEOGRAPHIC SEGMENT INFORMATION
During 1993, sales of oil to the Company's top two purchasers totaled
approximately 12 and 10 percent of oil revenue. During 1992, sales of oil to the
Company's top purchaser totaled approximately 25 percent of oil revenue. Sales
of gas to the Company's top purchaser in 1993 totaled approximately 14 percent
and in 1992 totaled approximately 19 percent of gas revenue. The Company
believes that the loss of any major purchaser would not have a material adverse
effect on the Company's business.
Financial information by segment for the years ended December 31, 1993, 1992
and 1991 are summarized as follows:
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- ----------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
December 31, 1993
Revenues
Oil and gas.............................................. $ 700 $ 265 $ 97 $ 18 $ 1,080
Other.................................................... (26) -- -- -- (26)
--------- ----------- ----- ----- ---------
Total Revenues............................................. 674 265 97 18 1,054
--------- ----------- ----- ----- ---------
Expenses
Operating costs.......................................... 186 127 29 3 345
Production taxes......................................... 52 9 44 7 112
Exploration costs........................................ 52 19 13 11 95
Depreciation, depletion and amortization................. 261 111 14 9 395
Miscellaneous............................................ 1 -- -- -- 1
--------- ----------- ----- ----- ---------
Total Operating Expenses................................... 552 266 100 30 948
--------- ----------- ----- ----- ---------
Operating Profit (Loss)*................................... $ 122 $ (1) $ (3) $ (12) 106
--------- ----------- ----- -----
--------- ----------- ----- -----
General and administrative expense....................... (98)
Interest, net............................................ (116)
Benefit for income taxes................................. 10
Remeasurement of foreign deferred tax.................... 5
Extraordinary item....................................... (7)
---------
Net Loss................................................... $ (100)
---------
---------
Capital Expenditures....................................... $ 202 $ 232** $ 13 $ 6 $ 453**
--------- ----------- ----- ----- ---------
--------- ----------- ----- ----- ---------
Identifiable Assets........................................ $ 1,861 $ 1,589 $ 103 $ 71 $ 3,624
--------- ----------- ----- ----- ---------
--------- ----------- ----- ----- ---------
<FN>
- ------------------------
*Provision (benefit) for income taxes on 1993 operating profits, calculated at
statutory rates, are $44 million and $(2) million for the United States and
Indonesia. No statutory tax benefit results from the Other Foreign operating
loss of $12 million.
**Includes capitalized interest of $46 million.
</TABLE>
40
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(14) GEOGRAPHIC SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- ----------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
December 31, 1992
Revenues
Oil and gas.............................................. $ 799 $ 335 $ 127 $ 14 $ 1,275
Other.................................................... 119 (2) -- -- 117
--------- ----------- ----- ----- ---------
Total Revenues............................................. 918 333 127 14 1,392
--------- ----------- ----- ----- ---------
Expenses
Operating costs.......................................... 215 149 26 7 397
Production taxes......................................... 62 17 58 -- 137
Exploration costs........................................ 67 24 13 8 112
Depreciation, depletion and amortization................. 276 108 21 4 409
Miscellaneous............................................ 1 4 -- -- 5
Provision for relinquishment of non-producing
properties.............................................. 63 -- -- -- 63
--------- ----------- ----- ----- ---------
Total Operating Expenses................................... 684 302 118 19 1,123
--------- ----------- ----- ----- ---------
Operating Profit*.......................................... $ 234 $ 31 $ 9 $ (5) 269
--------- ----------- ----- -----
--------- ----------- ----- -----
General and administrative expense....................... (120)
Interest, net............................................ (139)
Provision for restructuring.............................. (14)
Benefit for income taxes................................. 18
Remeasurement of foreign deferred tax.................... 59
Cumulative effect of change in accounting principle...... (59)
---------
Net Income................................................. $ 14
---------
---------
Capital Expenditures....................................... $ 101 $ 249** $ 12 $ 10 $ 372**
--------- ----------- ----- ----- ---------
--------- ----------- ----- ----- ---------
Identifiable Assets........................................ $ 2,086 $ 1,461 $ 113 $ 78 $ 3,738
--------- ----------- ----- ----- ---------
--------- ----------- ----- ----- ---------
<FN>
- ------------------------
*Provisions for income taxes on 1992 operating profits, calculated at statutory
rates, are $82 million, $8 million and $5 million for the United States,
United Kingdom and Indonesia. No statutory tax benefit results from the Other
Foreign operating loss of $5 million.
**Includes capitalized interest of $43 million.
</TABLE>
41
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(14) GEOGRAPHIC SEGMENT INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- ----------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
December 31, 1991
Revenues
Oil and gas.............................................. $ 947 $ 339 $ 177 $ 21 $ 1,484
Other.................................................... 111 3 1 (1) 114
--------- ----------- ----- ----- ---------
Total Revenues............................................. 1,058 342 178 20 1,598
--------- ----------- ----- ----- ---------
Expenses
Operating costs.......................................... 235 142 30 6 413
Production taxes......................................... 55 14 82 4 155
Exploration costs........................................ 160 50 8 4 222
Depreciation, depletion and amortization................. 313 96 35 4 448
Miscellaneous............................................ (3) 8 1 (1) 5
--------- ----------- ----- ----- ---------
Total Operating Expenses................................... 760 310 156 17 1,243
--------- ----------- ----- ----- ---------
Operating Profit*.......................................... $ 298 $ 32 $ 22 $ 3 355
--------- ----------- ----- -----
--------- ----------- ----- -----
General and administrative expense....................... (153)
Interest, net............................................ (186)
Provision for restructuring.............................. (53)
Benefit for income taxes................................. 56
---------
Net Income................................................. $ 19
---------
---------
Capital Expenditures....................................... $ 314 $ 175** $ 22 $ 16 $ 527**
--------- ----------- ----- ----- ---------
--------- ----------- ----- ----- ---------
Identifiable Assets........................................ $ 2,710 $ 1,303 $ 181 $ 63 $ 4,257
--------- ----------- ----- ----- ---------
--------- ----------- ----- ----- ---------
<FN>
- ------------------------
*Provisions for income taxes on 1991 operating profits, calculated at statutory
rates, are $105 million, $8 million and $12 million for the United States,
United Kingdom and Indonesia. No statutory tax burden results from the Other
Foreign operating profit of $3 million.
**Includes capitalized interest of $26 million.
</TABLE>
(15) STATEMENT OF CASH FLOWS
Amounts paid for interest and income taxes were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
-------- -------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Interest paid (net of capitalized interest).................. $ 119 $ 133 $ 174
Income taxes paid............................................ $ 14 $ 39 $ 132
</TABLE>
During 1993 and 1991, the Company recognized deferred tax liabilities of $3
million and $74 million associated with international properties acquisitions.
In 1991, the Company eliminated $87 million of long-term debt through the
cancellation of a $33 million capital lease obligation and the assumption of $54
million of debt by the purchaser of the Midway-Sunset Field producing oil and
gas assets. In accordance with Statement of Financial Accounting Standards No.
95, "Statement of Cash Flows," non-cash transactions are not reflected within
the accompanying Consolidated Statements of Cash Flows.
42
<PAGE>
ORYX ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(16) DEFERRED CREDITS AND OTHER LIABILITIES
At December 31, the Company's deferred credits and other liabilities were
comprised of the following:
<TABLE>
<CAPTION>
1993 1992
----------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Employee benefit obligations....................................... $ 75 $ 80
Deferred gains on interest futures................................. 37 10
Accrued acquisition financing...................................... 33 --
Minority interest in consolidated subsidiaries..................... 27 32
Accrued environmental cleanup costs................................ 20 20
Other.............................................................. 9 16
----- -----
$ 201 $ 158
----- -----
----- -----
</TABLE>
Environmental cleanup costs have been accrued in response to the
identification of several sites that require cleanup based on environmental
pollution, some of which have been designated as superfund sites by the
Environmental Protection Agency (EPA). The Company has been designated as a
Potentially Responsible Party (PRP) at a site in southern California where the
EPA is requiring the PRP's to undertake remediation of the site in several
phases. The Company is a member of the group that is responsible for carrying
out the first phase of the work, which is expected to take 5 to 8 years.
Completion of all phases is estimated to take up to 30 years. The maximum
liability of the group, which is joint and several for each member of the group,
is expected to range from approximately $450 million to $600 million, of which
the Company's share is expected to be approximately $10 million (net of $3
million in recoveries from third parties). Cleanup costs are payable over the
period that the work is completed.
43
<PAGE>
ORYX ENERGY COMPANY
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors, Oryx Energy Company:
We have audited the consolidated balance sheets of Oryx Energy Company and
its Subsidiaries as of December 31, 1993 and 1992, and the related consolidated
statements of income, cash flows and changes in shareholders' equity for each of
the three years in the period ended December 31, 1993. These financial
statements are the responsibility of the Company'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 Oryx Energy
Company and its Subsidiaries as of December 31, 1993 and 1992, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1993 in conformity with generally
accepted accounting principles.
As discussed in Note 1 to the Consolidated Financial Statements, in 1993 the
Company changed its methods of accounting for postretirement benefits other than
pensions and postemployment benefits and in 1992 the Company changed its method
of computing deferred income taxes.
COOPERS & LYBRAND
Dallas, Texas
February 19, 1994
44
<PAGE>
ORYX ENERGY COMPANY
SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION (UNAUDITED)
OIL AND GAS DATA
CAPITALIZED COSTS
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- ----------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
December 31, 1993
Proved properties.................................................. $ 4,193 $ 1,741 $ 185 $ 65 $ 6,184
Unproved properties................................................ 60 185 6 6 257
--------- ----------- ----- --- ---------
Total capitalized costs............................................ 4,253 1,926 191 71 6,441
Less accum. depr., depl. and amort................................. 2,605 417 98 18 3,138
--------- ----------- ----- --- ---------
Net capitalized costs.............................................. $ 1,648 $ 1,509 $ 93 $ 53 $ 3,303
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
December 31, 1992
Proved properties.................................................. $ 4,175 $ 1,512 $ 181 $ 65 $ 5,933
Unproved properties................................................ 68 189 4 5 266
--------- ----------- ----- --- ---------
Total capitalized costs............................................ 4,243 1,701 185 70 6,199
Less accum. depr., depl. and amort................................. 2,467 306 84 10 2,867
--------- ----------- ----- --- ---------
Net capitalized costs.............................................. $ 1,776 $ 1,395 $ 101 $ 60 $ 3,332
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
</TABLE>
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- ----------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
1993
Property acquisition costs:
Proved........................................................... $ 11 $ 33 $ -- $ -- $ 44
Unproved......................................................... 8 -- -- -- 8
Exploration costs.................................................. 62 15 15 11 103
Development costs.................................................. 147 147* 2 -- 296
--------- ----------- ----- --- ---------
Total.......................................................... $ 228 $ 195 $ 17 $ 11 $ 451
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
1992
Property acquisition costs:
Proved........................................................... $ -- $ -- $ -- $ -- $ --
Unproved......................................................... -- -- -- -- --
Exploration costs.................................................. 51 25 13 12 101
Development costs.................................................. 85 194* 8 2 289
--------- ----------- ----- --- ---------
Total.......................................................... $ 136 $ 219 $ 21 $ 14 $ 390
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
1991
Property acquisition costs:
Proved........................................................... $ 8 $ -- $ -- $ -- $ 8
Unproved......................................................... 27 -- 6 1 34
Exploration costs.................................................. 128 45 13 11 197
Development costs.................................................. 197 111* 13 9 330
--------- ----------- ----- --- ---------
Total.......................................................... $ 360 $ 156 $ 32 $ 21 $ 569
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
<FN>
- ------------------------
*Excludes capitalized interest of $46 million, $43 million and $26 million for
1993, 1992 and 1991.
</TABLE>
45
<PAGE>
EXPLORATION COSTS
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- ----------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
1993
Dry hole costs..................................................... $ 21 $ 5 $ 8 $ 3 $ 37
Leasehold impairment............................................... 3 4 -- 1 8
Geological and geophysical......................................... 26 9 5 7 47
Other.............................................................. 2 1 -- -- 3
--------- ----------- ----- --- ---------
$ 52 $ 19 $ 13 $ 11 $ 95
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
1992
Dry hole costs..................................................... $ 12 $ 4 $ 3 $ 2 $ 21
Leasehold impairment............................................... 26 8 1 -- 35
Geological and geophysical......................................... 28 11 9 5 53
Other.............................................................. 2 1 -- -- 3
--------- ----------- ----- --- ---------
$ 68 $ 24 $ 13 $ 7 $ 112
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
1991
Dry hole costs..................................................... $ 40 $ 22 $ 4 $ -- $ 66
Leasehold impairment............................................... 56 10 -- -- 66
Geological and geophysical......................................... 50 16 5 3 74
Other.............................................................. 14 1 -- 1 16
--------- ----------- ----- --- ---------
$ 160 $ 49 $ 9 $ 4 $ 222
--------- ----------- ----- --- ---------
--------- ----------- ----- --- ---------
</TABLE>
ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES
Proved reserves are the estimated quantities which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from reservoirs under existing economic and operating conditions.
Proved developed reserves are the quantities expected to be recovered through
existing wells with existing equipment and operating methods. These reserve
estimates were principally prepared by Company engineers and are based on
current technology and economic conditions. The Company considers such estimates
to be reasonable; however, due to inherent uncertainties and the limited nature
of reservoir data, estimates of underground reserves are imprecise and subject
to change over time as additional information becomes available.
There has been no major discovery or other favorable or adverse event that
has caused a significant change in estimated proved reserves since December 31,
1993. The Company has no long-term supply agreements or contracts with
governments or authorities in which it acts as producer nor does it have any
interest in oil and gas operations accounted for by the equity method.
46
<PAGE>
<TABLE>
<CAPTION>
CRUDE OIL AND CONDENSATE RECOVERABLE NATURAL
------------------------------------------------ GAS LIQUIDS NATURAL GAS
OTHER -------------------- -----------------------
PROVED RESERVES U.S. U.K. INDONESIA FOREIGN TOTAL U.S. U.S.* U.K. TOTAL
- --------------------------- ----- ----- ---------- -------- ------ -------------------- ------ ----- ------
(MILLIONS OF BARRELS) (MILLIONS OF (BILLIONS OF CUBIC
BARRELS) FEET)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1990...................... 457** 190 38 17 702 66 1,885 146 2,031
Revisions of previous
estimates............... (11) 5 2 -- (4) 6 13 2 15
Improved recovery........ 2 -- -- -- 2 -- 5 -- 5
Purchases of minerals in
place................... 1 -- -- -- 1 1 9 -- 9
Sales of minerals in
place................... (155) -- -- -- (155) -- (66) -- (66)
Extensions and
discoveries............. 28 8 -- 10 46 3 166 137 303
Production............... (28) (13) (9) (1) (51) (10) (237) (19) (256)
-- -- --
----- ----- ------ ------ ----- ------
Balance at December 31,
1991...................... 294 190 31 26 541 66 1,775 266 2,041
Revisions of previous
estimates............... (14) -- 5 -- (9) -- (31) -- (31)
Improved recovery........ 4 -- -- -- 4 -- 1 -- 1
Purchases of minerals in
place................... -- -- -- -- -- -- -- -- --
Sales of minerals in
place................... (21) -- -- (15) (36) (34) (198) -- (198)
Extensions and
discoveries............. 15 12 8 5 40 -- 177 196 373
Production............... (23) (13) (6) (1) (43) (7) (214) (35) (249)
-- -- --
----- ----- ------ ------ ----- ------
Balance at December 31,
1992...................... 255 189 38 15 497 25 1,510 427 1,937
Revisions of previous
estimates............... (4) (3) 4 2 (1) (1) 5 52 57
Improved recovery........ 1 -- -- -- 1 -- 1 -- 1
Purchases of minerals in
place................... -- 13 -- -- 13 -- 4 -- 4
Sales of minerals in
place................... (12) -- -- -- (12) (2) (66) -- (66)
Extensions and
discoveries............. 19 2 -- 8 29 2 168 -- 168
Production............... (21) (13) (5) (1) (40) (3) (191) (29) (220)
-- -- --
----- ----- ------ ------ ----- ------
Balance at December 31,
1993...................... 238 188 37 24 487 21 1,431 450 1,881
-- -- --
-- -- --
----- ----- ------ ------ ----- ------
----- ----- ------ ------ ----- ------
<CAPTION>
PROVED DEVELOPED RESERVES
AT DECEMBER 31
- ---------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1990......... 340** 101 31 1 473 60 1,431 123 1,554
1991......... 212 89 27 6 334 57 1,351 155 1,506
1992......... 175 76 27 3 281 20 1,069 121 1,190
1993......... 156 85 26 5 272 16 1,010 95 1,105
<FN>
- ------------------------------
*Natural gas reserve volumes include liquefiable hydrocarbons approximating 5
percent of total gas reserves which are recoverable at natural gas processing
plants downstream from the lease or field separation facilities. Such
recoverable liquids also have been included in natural gas liquids reserve
volumes.
**Includes approximately 140 million barrels of proved and 100 million barrels
of proved developed reserves of crude oil attributable to the Midway-Sunset
Field which was sold January 31, 1991 (see Note 4 to the Consolidated
Financial Statements).
</TABLE>
47
<PAGE>
ORYX ENERGY COMPANY
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES
The standardized measure of discounted future net cash flows from estimated
production of proved oil and gas reserves after income taxes is presented in
accordance with the provisions of SFAS No. 69, "Disclosures about Oil and Gas
Producing Activities" (SFAS No. 69). In computing this data, assumptions other
than those mandated by SFAS No. 69 could produce substantially different
results. The Company cautions against viewing this information as a forecast of
future economic conditions or revenues.
The standardized measure has been prepared assuming year-end selling prices
adjusted for future fixed and determinable contractual price changes, year-end
development, production and direct general and administrative costs, year-end
statutory tax rates adjusted for future tax rates already legislated and a ten
percent annual discount rate.
<TABLE>
<CAPTION>
UNITED UNITED OTHER
STATES KINGDOM INDONESIA FOREIGN TOTAL
--------- --------- ----------- ----------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
1993
Future cash inflows...................................... $ 5,802 $ 3,755 $ 461 $ 259 $ 10,277
Future production and development costs.................. (3,349) (2,785) (403) (190) (6,727)
Other related future costs............................... (303) (100) -- -- (403)
Future income tax expenses............................... (579) (116) (27) (10) (732)
--------- --------- ----------- ----------- ---------
Future net cash flows.................................... 1,571 754 31 59 2,415
Discount at 10 percent................................... (642) (307) (11) (27) (987)
--------- --------- ----------- ----------- ---------
Standardized measure of discounted future net cash flows
from estimated production of proved oil and gas reserves
after income taxes...................................... $ 929 $ 447 $ 20 $ 32 $ 1,428
--------- --------- ----------- ----------- ---------
--------- --------- ----------- ----------- ---------
1992
Future cash inflows...................................... $ 7,642 $ 4,509 $ 677 $ 207 $ 13,035
Future production and development costs.................. (3,719) (2,704) (531) (129) (7,083)
Other related future costs............................... (326) (100) -- (11) (437)
Future income tax expenses............................... (1,027) (137) (76) (10) (1,250)
--------- --------- ----------- ----------- ---------
Future net cash flows.................................... 2,570 1,568 70 57 4,265
Discount at 10 percent................................... (1,033) (781) (23) (20) (1,857)
--------- --------- ----------- ----------- ---------
Standardized measure of discounted future net cash flows
from estimated production of proved oil and gas reserves
after income taxes...................................... $ 1,537 $ 787 $ 47 $ 37 $ 2,408
--------- --------- ----------- ----------- ---------
--------- --------- ----------- ----------- ---------
</TABLE>
48
<PAGE>
ORYX ENERGY COMPANY
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME
TAXES
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Balance, beginning of year....................................................... $ 2,408 $ 2,875 $ 5,182
Increase (decrease) in discounted future net cash flows:
Sales of oil and gas production, net of related costs........................ (606) (746) (950)
Revisions to estimates of proved reserves:
Prices..................................................................... (1,389) (245) (3,629)
Development costs.......................................................... 3 (267) 152
Production costs........................................................... 99 534 638
Quantities................................................................. -- (66) 7
Other...................................................................... (89) (467) (536)
Extensions, discoveries and improved recovery, less related costs............ 111 282 375
Development costs incurred during the period................................. 321 303 358
Purchases of reserves in place............................................... 53 -- 10
Sales of reserves in place................................................... (59) (430) (527)
Accretion of discount........................................................ 298 371 710
Income taxes................................................................. 278 264 1,085
--------- --------- ---------
Balance, end of year............................................................. $ 1,428 $ 2,408 $ 2,875
--------- --------- ---------
--------- --------- ---------
</TABLE>
49
<PAGE>
ORYX ENERGY COMPANY
QUARTERLY FINANCIAL INFORMATION
During the fourth quarter of 1992, the Company adopted the provisions of
SFAS No. 109 retroactive to January 1, 1992 (see Note 1 to the Consolidated
Financial Statements). Certain information previously reported by the Company in
1992 was restated as a result of this change.
<TABLE>
<CAPTION>
QUARTER ENDED
--------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 TOTAL
----------- ----------- --------------- ------------- ---------
(MILLIONS OF DOLLARS EXCEPT, PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenue:
1993....................................................... $ 283 $ 278 $ 264 $ 229 $ 1,054
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
1992....................................................... $ 332 $ 368 $ 398 $ 294 $ 1,392
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
Gross profit:*
1993....................................................... $ 45 $ 64 $ 31 $ (1) $ 139
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
1992....................................................... $ 53 $ 59 $ 71 $ 71 $ 254
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
Net income (loss)**:
1993
Before extraordinary item................................ $ (7) $ 4 $ (45) $ (45) $ (93)
Extraordinary item....................................... -- -- -- (7) (7)
----- ----- ----- ----- ---------
Net income (loss)........................................ $ (7) $ 4 $ (45) $ (52) $ (100)
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
1992
As reported.............................................. $ (16) $ 40 $ 5 $ 25 $ 54
Restatement of income from continuing operations for
adoption of SFAS No. 109................................ 29 (38) 28 -- 19
----- ----- ----- ----- ---------
13 2 33 25 73
Cumulative effect of change in accounting principle...... (59) -- -- -- (59)
----- ----- ----- ----- ---------
As restated.............................................. $ (46) $ 2 $ 33 $ 25 $ 14
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
Net income (loss) per share of common stock:**
1993
Before extraordinary item................................ $ (.08) $ .03 $ (.48) $ (.48) $ (1.01)
Extraordinary item....................................... -- -- -- (.07) (.07)
----- ----- ----- ----- ---------
Net income (loss)........................................ $ (.08) $ .03 $ (.48) $ (.55) $ (1.08)
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
1992
As reported.............................................. $ (.23) $ .46 $ .03 $ .25 $ .52
Restatement of income from continuing operations for
adoption of SFAS No. 109................................ .36 (.47) .32 -- .22
----- ----- ----- ----- ---------
.13 (.01) .35 .25 .74
Cumulative effect of change in accounting principle...... (.74) -- -- -- (.68)
----- ----- ----- ----- ---------
As restated.............................................. $ (.61) $ (.01) $ .35 $ .25 $ .06
----- ----- ----- ----- ---------
----- ----- ----- ----- ---------
<FN>
- ------------------------
*Gross profit equals oil and gas revenues plus gas plant margins less
production cost, exploration cost and depreciation, depletion and
amortization.
**See Notes 1 and 9 to the Consolidated Financial Statements.
</TABLE>
50
<PAGE>
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
The information on directors required by this Item is incorporated herein by
reference to the section entitled "Election of Directors" on pages 2-4 of the
Company's definitive Proxy Statement dated March 23, 1994.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated herein by reference to
the section entitled "Executive Compensation" on pages 7-20 of the Company's
definitive Proxy Statement dated March 23, 1994.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated herein by reference to
the section entitled "Security Ownership of Management" on page 6 of the
Company's definitive Proxy Statement dated March 23, 1994.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated herein by reference to
the section entitled "Certain Transactions and Relationships" on page 20 of the
Company's definitive Proxy Statement dated March 23, 1994.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report:
1. Consolidated Financial Statements
2. Financial Statement Schedules
See Index to Financial Statements, Supplementary Financial and Operating
Information and Financial Statement Schedules on page 21.
Other schedules and separate financial statements of unconsolidated
subsidiaries are omitted because the information is shown elsewhere in this
report, is not required or is not applicable.
3. Exhibits:
<TABLE>
<C> <S> <C>
*3.1 -- Restated Certificate of Incorporation of the Registrant, as
currently in effect
**3.2 -- Amended and Restated Bylaws of the Registrant, as currently in
effect
***4.1 -- Form of Common Stock of the Registrant
****4.2 -- Rights Agreement dated as of September 11, 1990, between the
Registrant and Manufacturers Hanover Trust Company
+4.3 -- Indenture dated as of September 15, 1988 by and between The Bank of
New York and the Registrant
++4.4 -- First Supplemental Indenture by and between The Bank of New York and
the Registrant
+++10.1 -- Second Amended and Restated Agreement of Limited Partnership of Sun
Energy Partners, L.P.
+++10.2 -- Agreement of Limited Partnership of Sun Operating Limited
Partnership, as amended
</TABLE>
51
<PAGE>
<TABLE>
<C> <S> <C>
++++10.3 -- Registrant's Directors' Deferred Compensation Plan
++++10.4 -- Registrant's Non-Employee Directors' Retirement Plan
++++10.5 -- Employment Agreement between Robert P. Hauptfuhrer and the Regis-
trant
#10.5a -- Amendment to Employment Agreement between Robert P. Hauptfuhrer and
the Registrant, dated June 1, 1989
##10.5b -- Amendment to Employment Agreement between Robert P. Hauptfuhrer and
the Registrant, dated December 3, 1992
++++10.6 -- Registrant's Pension Restoration Plan
###10.6a -- Amendment to Registrant's Pension Restoration Plan
++++10.7 -- Registrant's Executive Retirement Plan
###10.7a -- Amendment to Registrant's Executive Retirement Plan
####10.8 -- Registrant's Executive Long-Term Incentive Plan
#10.8a -- Amendment to Registrant's Executive Long-Term Incentive Plan, dated
February 1, 1989
#10.8b -- Amendment to Registrant's Executive Long-Term Incentive Plan, dated
February 6, 1989
####10.9 -- Registrant's Long-Term Incentive Plan
#10.9a -- Amendment to Registrant's Long-Term Incentive Plan, dated February
1, 1989
#10.9b -- Amendment to Registrant's Long-Term Incentive Plan, dated February
6, 1989
#10.9c -- Amendment to Registrant's Long-Term Incentive Plan, dated May 31,
1989
m10.10 -- Registrant's 1992 Long-Term Incentive Plan
#10.11 -- Registrant's Executive Annual Incentive Plan
++++10.12 -- Registrant's Savings Restoration Plan
###10.12a -- Amendment to Registrant's Savings Restoration Plan
++++10.13 -- Registrant's Amended and Restated Executive Deferred Compensation
Plan
###10.13a -- Amendment to Registrant's Amended and Restated Executive Deferred
Compensation Plan
++++10.14 -- Registrant's Deferred Compensation and Benefits Trust
++++10.15 -- Registrant's Special Employee Severance Plan
++++10.16 -- Registrant's Special Executive Severance Plan
###10.16a -- Amendment to Registrant's Special Executive Severance Plan
****10.17 -- Revolving Credit and Term Loan Agreement among the Registrant and
the banks named therein, dated as of September 10, 1990
mm10.18 -- Sale and Purchase Agreements by and between BP Petroleum Develop-
ment Limited et al and the Registrant
##10.19 -- Oryx Energy Company Capital Accumulation Plan, As Amended and Re-
stated Generally Effective as of January 1, 1993
##10.20 -- Oryx Energy Company $620,000,000 Revolving Credit Agreement Dated as
of December 31, 1992
12 -- Computation of Consolidated Ratio of Earnings to Fixed Charges and
Earnings to Fixed Charges and Preferred Stock Dividend Requirements
</TABLE>
52
<PAGE>
<TABLE>
<C> <S> <C>
mmm19 -- Distribution Agreement dated August 28, 1991 relating to Medium-Term
Notes, Series A
#22 -- Subsidiaries
24 -- Consent of Coopers & Lybrand
25 -- Power of Attorney
<FN>
- ------------------------
* Incorporated by reference to the Registrant's Quarterly Report on Form
10-Q for the quarter ended March 31, 1992 (File No. 1-10053) filed with
the Commission on May 15, 1992.
** Incorporated by reference to the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 1990 (File No. 1-10053) filed
with the Commission on November 14, 1990.
*** Incorporated by reference to the Registrant's Form 8-K (File No.
1-10053) filed with the Commission on September 25, 1990.
**** Incorporated by reference to the Registrant's Registration Statement on
Form 8-A (File No. 1-10053) filed with the Commission on September 19,
1990.
+ Incorporated by reference to the Registrant's Registration Statement on
Form S-1 (File No. 33-24214) filed with the Commission on September 8,
1988.
++ Incorporated by reference to the Registrant's Amendment No. 2 on Form
S-3 (File No. 33-33361) filed with the Commission on June 29, 1990.
+++ Incorporated by reference to the Form SE of Sun Energy Partners, L.P.
filed with the Commission on March 20, 1986.
++++ Incorporated by reference to the Registrant's Registration Statement on
Form S-1 (File No. 33-27723) filed with the Commission on March 22,
1989.
# Incorporated by reference to the Registrant's Registration Statement on
Form S-1 (File No. 33-33361) filed with the Commission on February 6,
1990.
## Incorporated by reference to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1992 (File No. 1-10053)
filed with the Commission on March 22, 1993.
### Incorporated by reference to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1991 (File No. 1-10053)
filed with the Commission on March 19, 1992.
#### Incorporated by reference to the Registrant's Registration Statement on
Form S-1 (File No. 33-24214) filed with the Commission on September 8,
1988.
m Incorporated by reference to Exhibit A of the Company's definitive
Proxy Statement (File No. 1-10053) dated March 25, 1991.
mm Incorporated by reference to the Registrant's Form 8-K (File No.
1-10053) filed with the Commission on December 26, 1989.
mmm Incorporated by reference to the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 1991 (File No. 1-10053) filed
with the Commission on November 14, 1991.
</TABLE>
(b) Reports on Form 8-K:
The Company did not file any reports on Form 8-K during the quarter ended
December 31, 1993.
53
<PAGE>
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.
ORYX ENERGY COMPANY
By: /s/ EDWARD W. MONEYPENNY
--------------------------------------
EDWARD W. MONEYPENNY
SENIOR VICE PRESIDENT, FINANCE,
AND CHIEF FINANCIAL OFFICER
Date: March 11, 1994
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 date indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- ------------------------------------------------------ ------------------------------------- ------------------
<C> <S> <C>
ROBERT P. HAUPTFUHRER* Chairman of the Board, and Chief
------------------------------------------- Executive Officer (principal
Robert P. Hauptfuhrer executive officer)
ROBERT L. KEISER* President, Chief Operating Officer
------------------------------------------- and Director
Robert L. Keiser
/s/ EDWARD W. MONEYPENNY Senior Vice President, Finance, and
------------------------------------------- Chief Financial Officer (principal
Edward W. Moneypenny financial officer)
BARRY L. STRONG* Comptroller (principal accounting
------------------------------------------- officer)
Barry L. Strong
WILLIAM E. BRADFORD* Director
-------------------------------------------
William E. Bradford
CAROL E. DINKINS* Director March 11, 1994
-------------------------------------------
Carol E. Dinkins
ROBERT B. GILL* Director
-------------------------------------------
Robert B. Gill
C. JACKSON GRAYSON, JR.* Director
-------------------------------------------
C. Jackson Grayson, Jr.
DAVID S. HOLLINGSWORTH* Director
-------------------------------------------
David S. Hollingsworth
CHARLES H. PISTOR, JR.* Director
-------------------------------------------
Charles H. Pistor, Jr.
PAUL R. SEEGERS* Director
-------------------------------------------
Paul R. Seegers
IAN L. WHITE-THOMSON* Director
-------------------------------------------
Ian L. White-Thomson
*By: /s/ EDWARD W. MONEYPENNY
---------------------------------------
Edward W. Moneypenny
ATTORNEY-IN-FACT
<FN>
- ------------------------
*A Power of Attorney authorizing Robert P. Hauptfuhrer and Edward W. Moneypenny,
and each of them, to sign this Form 10-K Annual Report on behalf of the
directors, constituting a majority of the Board of Directors, and certain
officers of Oryx Energy Company, is being filed with the Securities and
Exchange Commission.
</TABLE>
54
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors of Oryx Energy Company:
Our report on the consolidated financial statements of Oryx Energy Company
and its Subsidiaries is included on page 44 of this Form 10-K. In connection
with our audits of such financial statements, we have also audited the related
financial statement schedules listed in the index on page 21 of this Form 10-K.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects, the information required to be
included therein.
COOPERS & LYBRAND
Dallas, Texas
February 19, 1994
55
<PAGE>
ORYX ENERGY COMPANY
SCHEDULE V -- PROPERTIES, PLANTS AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
BALANCE AT OTHER BALANCE AT
BEGINNING ADDITIONS RETIREMENTS CHANGES END OF
OF PERIOD AT COST OR SALES(A) ADD (DEDUCT) PERIOD
----------- ----------- ------------- ----------------- -----------
<S> <C> <C> <C> <C> <C>
For the year ended December 31, 1993............. $ 6,280 $ 453 $ 208 $ (2) $ 6,523
----------- ----- ----- --- -----------
----------- ----- ----- --- -----------
For the year ended December 31, 1992............. $ 6,805 $ 372 $ 899 $ 2 $ 6,280
----------- ----- ----- --- -----------
----------- ----- ----- --- -----------
For the year ended December 31, 1991............. $ 6,677 $ 527 $ 467 $ 68(B) $ 6,805
----------- ----- ----- --- -----------
----------- ----- ----- --- -----------
<FN>
- ------------------------
(A) Includes dry hole costs.
(B) Consists principally of $74 million of deferred tax liability recognized on
properties located in the United Kingdom. (See Note 15 to the Consolidated
Financial Statements.)
</TABLE>
56
<PAGE>
ORYX ENERGY COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION
AND AMORTIZATION OF PROPERTIES, PLANTS AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
BALANCE AT ADDITIONS CHARGED OTHER BALANCE AT
BEGINNING TO COST AND RETIREMENTS CHANGES END OF
OF PERIOD EXPENSES (A)(B) OR SALES ADD (DEDUCT) PERIOD
----------- ----------------- ----------- ----------------- -----------
<S> <C> <C> <C> <C> <C>
For the year ended December 31, 1993....... $ 2,915 $ 403 $ (119) $ (9) $ 3,190
----------- ----- ----------- --- -----------
----------- ----- ----------- --- -----------
For the year ended December 31, 1992....... $ 3,043 $ 507 $ 627 $ (8) $ 2,915
----------- ----- ----------- --- -----------
----------- ----- ----------- --- -----------
For the year ended December 31, 1991....... $ 2,832 $ 514 $ 314 $ 11 $ 3,043
----------- ----- ----------- --- -----------
----------- ----- ----------- --- -----------
<FN>
- ------------------------
(A) Depreciation, depletion and amortization.......... $ 395 $ 409 $ 448
Leasehold impairment.............................. 8 35 66
Provision for relinquishment of non-producing
properties........................................ -- 63 --
----- ----- -----
Total additions................................... 403 507 514
Dry hole costs.................................... 37 21 66
----- ----- -----
Amounts shown in the Consolidated Statements of
Cash Flows as depreciation, depletion and
amortization, provision for relinquishment of
non-producing properties, leasehold impairment and
dry hole costs.................................... $ 440 $ 528 $ 580
----- ----- -----
----- ----- -----
(B) Depreciation, depletion and amortization is calculated primarily using
the unit-of-production method. (See Note 1 to the Consolidated
Financial Statements.)
</TABLE>
57
<PAGE>
ORYX ENERGY COMPANY
SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Maintenance and repairs..................................................................... $ 48 $ 57 $ 80
--- --- ---------
--- --- ---------
Royalties paid to foreign governments....................................................... $ 60 $ 75 $ 103
--- --- ---------
--- --- ---------
</TABLE>
58
<PAGE>
EXHIBIT 12
ORYX ENERGY COMPANY
COMPUTATIONS OF CONSOLIDATED RATIOS OF EARNINGS
TO FIXED CHARGES AND EARNINGS TO FIXED CHARGES AND
PREFERRED STOCK DIVIDEND REQUIREMENTS -- UNAUDITED (A)
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
RATIO OF EARNINGS TO FIXED CHARGES:
Fixed Charges:
Consolidated interest cost and debt expense......................... $ 163 $ 187 $ 217 $ 241 $ 115
Interest allocable to rental expense (b)............................ 11 11 13 10 8
--------- --------- --------- --------- ---------
Total............................................................. $ 174 $ 198 $ 230 $ 251 $ 123
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Earnings:
Consolidated income (loss) before provision (credit) for income
taxes.............................................................. $ (108) $ (4) $ (52) $ 327 $ 81
Fixed charges....................................................... 174 198 230 251 123
Interest capitalized................................................ (46) (43) (26) (13) (13)
Amortization of previously capitalized interest..................... 7 3 3 3 4
--------- --------- --------- --------- ---------
Total............................................................. $ 27 $ 154 $ 155 $ 568 $ 195
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Ratio of Earnings to Fixed Charges (c)................................ .16 .78 .67 2.26 1.59
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND
REQUIREMENTS:
Fixed Charges:
Consolidated interest cost and debt expense......................... $ 163 $ 187 $ 217 $ 241 $ 115
Preferred stock dividend requirements (d)........................... 8 14 20 10 0
Interest allocable to rental expense (b)............................ 11 11 13 10 8
--------- --------- --------- --------- ---------
Total............................................................. $ 182 $ 212 $ 250 $ 261 $ 123
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Earnings:
Consolidated income (loss) before provision (credit) for income
taxes.............................................................. $ (108) $ (4) $ (52) $ 327 $ 81
Fixed charges....................................................... 182 212 250 261 123
Interest capitalized................................................ (46) (43) (26) (13) (13)
Amortization of previously capitalized interest..................... 7 3 3 3 4
--------- --------- --------- --------- ---------
Total............................................................. $ 35 $ 168 $ 175 $ 578 $ 195
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Ratio of Earnings to Fixed Charges (c)................................ .19 .79 .70 2.21 1.59
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
<FN>
- ------------------------
(a) The consolidated financial statements of Oryx Energy Company include the
accounts of all subsidiaries (more than 50 percent owned and/or controlled).
(b) Represents one-third of total operating lease rental expense which is that
portion deemed to be interest.
(c) Earnings for 1993 were inadequate to cover fixed charges, or fixed charges
and preferred stock dividend requirements, by $147 million. Earnings for
1992 were inadequate to cover fixed charges, or fixed charges and preferred
stock dividend requirements by $44 million. Earnings for 1991 were
inadequate to cover fixed charges, or fixed charges and preferred stock
dividend requirements, by $75 million.
(d) The Company did not have preferred stock dividend requirements prior to
1990.
</TABLE>
59
<PAGE>
EXHIBIT 24
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the Form S-8 registration
statements of the Oryx Energy Company Long-Term Incentive Plan (File No.
33-25032), the Oryx Energy Company Capital Accumulation Plan (File No.
33-24918), the Oryx Energy Company 1992 Long-Term Incentive Plan (File No.
33-42695) and the Form S-3 registration statements of Oryx Energy Company (File
No.'s 33-33361, 33-36799 and 33-45611), of our reports dated February 19, 1994,
on our audits of the consolidated financial statements and financial statement
schedules of Oryx Energy Company and its Subsidiaries as of December 31, 1993
and 1992 and for each of the three years in the period ended December 31, 1993,
which reports are included in this Form 10-K.
COOPERS & LYBRAND
Dallas, Texas
March 11, 1994
60
<PAGE>
EXHIBIT 25
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Robert P. Hauptfuhrer and Edward W. Moneypenny,
and each of them (with full power to each of them to act alone), his or her true
and lawful attorney-in-fact and agent, with full power of substitution and
resubstitution, for him or her and in his or her name, place and stead, in any
and all capacities to sign the Annual Report of Oryx Energy Company for the
fiscal year ended December 31, 1993 on Form 10-K pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934 and any or all amendments to the Annual
Report and to file the same, with all exhibits thereto and other documents in
connection therewith with the Securities and Exchange Commission, granting unto
said attorneys-in-fact and agents, and each of them, full power and authority to
do and perform each and every act and thing requisite and necessary to be done
in and about the premises, as fully to all intents and purposes as he or she
might or could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents or any of them, or their substitutes, may lawfully
do or cause to be done by virtue hereof.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- ------------------------------------------------------ -------------------------------------- -----------------
<C> <S> <C>
/s/ ROBERT P. HAUPTFUHRER Chairman of the Board, and Chief March 3, 1994
------------------------------------------- Executive Officer (principal
Robert P. Hauptfuhrer executive officer)
/s/ ROBERT L. KEISER President, Chief Operating Officer and March 3, 1994
------------------------------------------- Director
Robert L. Keiser
/s/ EDWARD W. MONEYPENNY Senior Vice President, Finance, and March 3, 1994
------------------------------------------- Chief Financial Officer (principal
Edward W. Moneypenny financial officer)
/s/ BARRY L. STRONG Comptroller (principal accounting March 3, 1994
------------------------------------------- officer)
Barry L. Strong
/s/ WILLIAM E. BRADFORD Director March 3, 1994
-------------------------------------------
William E. Bradford
/s/ CAROL E. DINKINS Director March 3, 1994
-------------------------------------------
Carol E. Dinkins
/s/ ROBERT B. GILL Director March 3, 1994
-------------------------------------------
Robert B. Gill
/s/ C. JACKSON GRAYSON, JR. Director March 3, 1994
-------------------------------------------
C. Jackson Grayson, Jr.
/s/ DAVID S. HOLLINGSWORTH Director March 3, 1994
-------------------------------------------
David S. Hollingsworth
/s/ CHARLES H. PISTOR, JR. Director March 3, 1994
-------------------------------------------
Charles H. Pistor, Jr.
/s/ PAUL R. SEEGERS Director March 3, 1994
-------------------------------------------
Paul R. Seegers
/s/ IAN L. WHITE-THOMSON Director March 3, 1994
-------------------------------------------
Ian L. White-Thomson
</TABLE>
61
