SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Fiscal Year ended DECEMBER 31, 1994
Commission file number 1-959
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
THE LOUISIANA LAND AND EXPLORATION COMPANY
Exact name of registrant as specified in its charter
MARYLAND 72-0244700
State or other jurisdiction of I.R.S. Employer
incorporation or organization Identification No.
909 POYDRAS STREET, NEW ORLEANS, LA. 70112
Address of principal executive offices Zip Code
Registrant's telephone number, including area code 504-566-6500
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE ON WHICH
TITLE OF EACH CLASS REGISTERED
Capital Stock, $.15 par New York Stock Exchange
value (including Capital London Stock Exchange
Stock Purchase Rights) The Stock Exchanges of Geneva,
Zurich and Basle
8-1/4% Notes due 2002 New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
(continued)
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
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 and
(2) has been subject to such filing requirements for the past 90
days. YES X . NO .
State the aggregate market value of the voting stock held by
non-affiliates of the registrant.
Aggregate Market Value
Class of Voting Stock at February 28, 1995
Capital Stock, $.15 par value $1,155,866,000
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest practicable
date.
Outstanding at
Class February 28, 1995
Capital Stock, $.15 par value 33,382,406 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part III: The Registrant's Proxy Statement for its Annual Meeting
of Stockholders to be held on May 11, 1995
INDEX
Page
Number
_________________________________________________________________
PART I
4 Items 1 and 2. Business and Properties.
4 The Company
4 Contributions of Principal Products
5 Petroleum Operations
6 General
7 Sales
8 Oil and Gas Properties
9 Oil and Gas Reserves
9 Exploration Activities
14 Development Activities
18 Drilling Activities at December 31, 1994
18 Oil and Gas Wells
20 Crude and Condensate, Plant Products and Natural Gas
Production and Prices Realized
21 Refining Operations
22 Regulation
22 Federal Energy Regulatory Commission
22 Environmental Matters
24 Item 3. Legal Proceedings.
24 Item 4. Submission of Matters to a Vote of Security
Holders.
25 Executive Officers of the Registrant
PART II
26 Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters.
26 Item 6. Selected Financial Data.
26 Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
27 Item 8. Financial Statements and Supplementary Data.
91 Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
PART III
91 Item 10. Directors and Executive Officers of the Registrant.
91 Item 11. Executive Compensation.
91 Item 12. Security Ownership of Certain Beneficial Owners and
Management.
91 Item 13. Certain Relationships and Related Transactions.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K.
92 (a)(1) Financial Statements and Supplementary Data
92 (a)(2) Financial Statement Schedules
92 (a)(3) Index to Exhibits
92 (b) Reports on Form 8-K
96 Signatures
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
The Company
The Louisiana Land and Exploration Company and subsidiaries
(LL&E or the Company) is engaged principally in the exploration for
and the development and production of petroleum natural resources.
The major portion of LL&E's petroleum operations are conducted in
the continental United States, the federal offshore area in the
Gulf of Mexico, the North Sea, Canada, Colombia and Indonesia. In
early 1995, the Company announced plans to sell certain non-
strategic assets, including remaining oil and gas assets in Canada,
which were not material to the Company's operations. LL&E also
owns a refinery in Alabama, and also processes natural gas. At
December 31, 1994, LL&E had 825 employees.
Contributions of Principal Products
The table below sets forth the principal products and their
contribution to the operating revenues of LL&E's petroleum
operations for the periods indicated. Reference is made to Note 16
of "Notes to Consolidated Financial Statements" for additional
information on LL&E's operations.
Years ended December 31,
(Millions of dollars) 1994 19931 1992
_______________________________________________________________________________________
Crude and condensate $ 235.8 210.0 215.1
Natural gas 169.9 146.0 92.0
Refined products2 361.4 400.2 441.9
Other petroleum products 15.4 14.1 16.8
_______________________________________________________________________________________
Total $ 782.5 770.3 765.8
_______________________________________________________________________________________
1 Includes NERCO Oil & Gas, Inc. since October 1, 1993.
2 After elimination of intercompany transfers to the Company's refinery. In 1994, 1993 and
1992, such transfers were valued at $24.8, $22.4 and $20.7, respectively.
Petroleum Operations
LL&E employs a staff of petrotechnical professionals to
initiate, evaluate, plan and execute LL&E's petroleum activities.
Typically, the actual tasks of exploration and development, such as
seismic surveys and drilling, are performed by independent
specialized contractors under the direction of LL&E's professional
staff. LL&E's principal domestic exploration activities at
December 31, 1994 were in the Gulf of Mexico, Louisiana and
Wyoming. Outside the United States, LL&E's principal exploration
activities were in the North Sea, Colombia, Algeria and Yemen.
In the United States, LL&E has working interests in
development and producing operations principally in Alabama,
Florida, Louisiana, Wyoming and the federal offshore area in the
Gulf of Mexico. Outside the United States, LL&E has working
interests in development and producing operations in the
Netherlands and United Kingdom sectors of the North Sea, Colombia
and Indonesia.
The majority of LL&E's working interest activities occur on
property leased from others, which leaseholds are acquired by
paying a signature bonus, delay rental and production royalty to
the owner of the mineral rights. In 1994, working interest
revenues accounted for 90% of LL&E's total oil and gas revenues.
LL&E receives income from royalties from production by others
of oil and gas from portions of the properties LL&E owns and leases
in south Louisiana. In addition, LL&E receives income from
geophysical options and the leasing of mineral rights to explore
undeveloped portions of these properties.
CLAM Petroleum Company (CLAM), a 50%-owned, unconsolidated
affiliate, is engaged in oil and gas exploration, development and
production activities in the Netherlands sector of the North Sea.
The tables on the following pages set forth LL&E's 50% equity
interest in the operations of CLAM.
LL&E Petroleum Marketing, Inc., a wholly owned subsidiary,
owns and operates a refinery in Mobile, Alabama. The refinery
utilizes various sources of feedstocks including Company-owned and
-controlled crude oil which is acquired on a competitive basis with
other domestic and foreign crudes from third parties.
GENERAL
LL&E's petroleum operations are subject to all of the risks
and uncertainties normally incident to exploration for and
development of oil and gas. Significant capital expenditures are
required in connection with such operations, with capital
expenditures for offshore operations typically being substantially
greater than for similar operations onshore. LL&E's earnings and
the scope of its future exploration and development programs will
be affected by the extent to which state and federal legislation
and regulations applicable to the petroleum industry impact
incentives for exploration and production, and permit the recovery
of revenues sufficient to meet increasing costs and to expand
operations. The marketability of offshore production is limited by
the availability of marine transportation facilities, which are
barge or pipeline for oil, but only pipeline for gas. In instances
where there are no gas pipelines in an area of production, LL&E
must await the permitting, certification and construction of
pipeline facilities before deliveries of gas can commence. A
portion of LL&E's petroleum operations is conducted in foreign
countries where LL&E is also subject to regulation, risks of a
political nature and other risks. LL&E's oil and gas production is
from properties in jurisdictions in which well drilling and
production are regulated or subject to limitations by governmental
production and conservation authorities.
The oil and gas industry is highly competitive in all phases,
including the search for and development of new sources of supply
and the refining and marketing of crude oil and petroleum products.
The oil and gas industry also competes with other industries that
supply energy and fuel, and LL&E competes with a number of major
integrated oil companies and other companies having greater
resources. LL&E participates in bidding for federal leases on the
U.S. Outer Continental Shelf, as well as for leases (concessions)
in other countries; participation in the bidding for these leases
is extremely competitive.
The principal raw materials and supplies required directly by
LL&E for its petroleum operations, other than refining and natural
gas processing, are generally available through multiple sources
and acquired through specialized independent contractors. The
refinery and gas processing operations' principal raw materials are
crude oil and natural gas, a portion of which is Company-owned and
-controlled. Internally generated fuels and electricity are the
principal energy requirements for the petroleum operations and the
refinery, and electricity is the principal energy requirement at
the gas processing plants. No serious problems currently exist
with respect to the availability of any of these items.
SALES
The availability of a ready market for oil and gas depends
upon numerous factors beyond the Company's control, including the
production of crude oil and gas by others, crude oil imports, the
marketing of competitive fuels, the proximity and capacity of oil
and gas pipelines, the availability of treatment facilities, the
regulation of allowable production by governmental authorities and
the regulation by the Federal Energy Regulatory Commission (FERC)
and various state agencies of the transportation and marketing of
natural gas transported or sold in interstate commerce (see
"Regulation").
Liquids
During 1994, LL&E's crude oil, condensate and plant products
production were sold into various domestic and international
markets at prices competitive for the area and for quality of
production. In some instances, crude oil, condensate and plant
products were traded from area to area and were then sold to third
parties or transferred to the Company's refinery. LL&E charged
transfers of proprietary production to its refinery at appropriate
market prices. The 1994 sales period has seen dramatic price
fluctuations with crude oil prices ranging between $14/BBL and
$21/BBL. Overall, crude oil prices averaged approximately $17/BBL
at Cushing, Oklahoma for West Texas Intermediate. This price was
approximately $1.50/BBL below the price averaged in 1993.
Natural Gas
Prior to FERC Orders 436/500 and 636, most of LL&E's sales of
natural gas were made to various interstate and intrastate gas
pipeline companies under long-term take-or-pay contracts subject to
the regulations of the FERC. With the implementation of the above-
referenced orders, the structure of the industry has changed
drastically. LL&E now has the ability, as other producers do, to
ship gas on the nationwide transportation grid and contract
directly with downstream customers. Development of this downstream
marketing activity has allowed LL&E to gain entry into markets not
previously available, reduced the Company's reliance on pipelines
to purchase natural gas and given the Company greater flexibility
and control of its natural gas reserves.
As of February 1, 1995, less than 5 percent of LL&E's natural
gas production was being sold to interstate pipeline companies.
The remainder of the Company's North American natural gas
production is sold primarily to local distribution companies,
industrials, electric utilities and aggregators under short- or
medium-term contracts at market-responsive prices. The vast
majority of the Company's North Sea gas production is sold to
distributors, electric generators and aggregators under long-term
contracts at prices based on various combinations of commodity and
inflation-based indices.
Refined Products
LL&E's refinery products, which include three grades of
gasoline, naphtha, two grades of No. 2 fuel oil, turbine fuel,
vacuum gas-oil and vacuum residuum, are generally sold in the spot
market, wholesale markets, or under short-term contracts. Products
are either sold in local or Gulf Coast markets or exchanged in
return for products in pipeline markets.
OIL AND GAS PROPERTIES
Information regarding LL&E's productive and undeveloped
acreage is presented under the heading "Oil and Gas Properties" in
Part II, Item 8. - "Financial Statements and Supplementary Data."
Working Interest Properties
At December 31, 1994, LL&E had working interests in
approximately 626 thousand gross (287 thousand net) productive
acres and approximately 7.4 million gross (3 million net)
undeveloped acres. The total unamortized cost to LL&E of such
undeveloped acreage at December 31, 1994 was $51.7 million.
Through its affiliate, CLAM Petroleum Company, LL&E had working
interests in approximately 40 thousand gross (6 thousand net)
productive acres and approximately 772 thousand gross (177 thousand
net) undeveloped acres, all located in the Netherlands sector of
the North Sea.
Leaseholds held by LL&E in the United States on privately
owned lands generally reserve to the lessor a 12-1/2% to 25%
royalty interest in the production from such lands. Federal leases
offshore in the Outer Continental Shelf are acquired by sealed
bids, and generally provide for a royalty of 16-2/3% of the value
of production. Federal leases onshore generally are acquired by
payment of a filing fee and provide for a royalty of 16-2/3% of the
value of production. The primary terms of LL&E's leases vary
generally from 3 to 10 years (five years in the case of federal
offshore leases), but such leases are automatically extended by
production for as long thereafter as production continues.
Royalty Properties
At December 31, 1994, LL&E owned approximately 594 thousand
acres in fee lands in south Louisiana of which approximately 142
thousand acres were leased to various other companies for oil and
gas exploration, development and production. Of those leased to
others, approximately 97 thousand acres are productive and yielded
a weighted average royalty to LL&E of 25%. In addition, LL&E holds
State of Louisiana leases covering approximately 55 thousand pro-
ductive acres which have been assigned to Texaco Inc. under a
contract (1928 Texaco Contract). Under the 1928 Texaco Contract,
which also covers certain fee lands owned by LL&E, LL&E is entitled
to receive a 25% royalty interest in the production from the
acreage subject to the lease. LL&E is obligated to pay to the
lessor of the leasehold interests subject to the 1928 Texaco
Contract a royalty which is, in most cases, 12-1/2% of the proceeds
from production for such property.
Of the approximately 452 thousand fee acres not leased to
others, LL&E conducts operations on approximately 1.1 thousand
productive acres; the balance of the fee acreage is classified as
undeveloped. From time to time, LL&E conducts exploratory
activities on this undeveloped fee acreage.
OIL AND GAS RESERVES
Information regarding LL&E's proved oil and gas reserves is
presented under the heading "Data on Oil and Gas Activities" in
Part II, Item 8. - "Financial Statements and Supplementary Data."
LL&E and its oil and gas subsidiaries are required to report, at
varying times, estimates of oil and gas reserve data with various
governmental authorities and agencies, including the Federal Energy
Regulatory Commission. The basis for reporting estimates of
reserves to these authorities and agencies may not be comparable to
that presented because of the nature of the various reports
required. The major sources of noncomparability include
differences in the times as of which such estimates are made and
differences in the definition of the reporting unit, such as,
gross, net, total operator, lease by lease, reservoir by reservoir.
EXPLORATION ACTIVITIES
Working Interest
The Company's exploration expenditures totaled $90 million in
1994: $17 million was spent on gathering and evaluating seismic
data, over $3 million was expended for unproved leases in the
United States and overseas, and $70 million was expended for
participation in 44 wells. Of this total, 27 wells were successful
completions: 5 oil and 22 gas.
South Louisiana
One of the Company's most significant gas discoveries in
recent years was announced in early 1994 following the successful
completion of an exploratory well in a deeper reservoir in the
Fresh Water Bayou Field in Vermilion Parish, Louisiana. The
Louisiana Furs C-16 well, drilled to a total depth of 19,260 feet
and completed, in a producing horizon below 17,500 feet, tested at
a rate of 30.3 million cubic feet of gas per day and 192 barrels of
condensate per day. The Company owns a 35% gross working interest
in the field. A development plan was initiated based on the
results from this discovery well. The first development well, the
Louisiana Furs C-17, was drilled to a total depth of 20,600 feet
and was completed in August in the same producing sand as the C-16
well. The C-17 tested 45.7 million cubic feet of gas per day and
307 barrels of condensate per day. A third development well, the
Louisiana Furs C-19, was then drilled and tested 29 million cubic
feet of gas per day and 329 barrels of condensate per day. Total
gross production from the first two wells has been limited to 55
million cubic feet of gas per day due to pipeline constraints and
limited production facilities. Expanded facilities and a new
pipeline increased gross production volumes from the field to over
100 million cubic feet of gas per day in March of 1995. Production
capacity of approximately 200 million cubic feet of gas per day
will be completed by year end in anticipation of the completion of
the two new development wells.
A 3-D seismic survey was conducted in late 1994 to assist in
the further development of the field. Based on information derived
from this survey as well as production information from the wells
currently onstream, at least two more drilling locations have been
identified for drilling during 1995. A potential deeper gas
horizon found but not tested in the initial well has also been
identified on the 3-D survey and is expected to be tested by one of
the two 1995 wells.
Interest in 3-D survey acquisition and analysis continued to
surge in the mature producing areas of south Louisiana during 1994.
The Company was active in 3-D seismic acquisition, adding 267 miles
to its inventory. Another 425 square miles is in the execution or
planning stages for 1995. Leveraging the value of the Company's
600,000 acre fee land ownership has enabled the Company to
structure a variety of arrangements with its partners to maximize
data acquisition and drilling exposure while greatly reducing
project costs and risk.
The effort expended in the acquisition and interpretation of
this seismic data over the last two years began to yield meaningful
drilling results during 1994. Three successful exploratory wells
were drilled on the basis of 3-D seismic. At the Bastian Bay
Field, a mature field where the last successful well was drilled in
1981, two 3-D prospects, Mustang and Vino, were successfully
completed. Mustang is currently producing 4 million cubic feet of
gas per day and 122 barrels of condensate per day and Vino tested
3.5 million cubic feet of gas per day and will be connected for
production shortly. The Company owns a 33% working interest in
both wells. Due to the Company's fee land ownership in the field
and its related royalty interest, the Company's net revenue
interests in the two wells are 40.8% and 48.4%, respectively. A
second successful 3-D well was also drilled at the Lake Washington
Field in late 1994 which recently tested 605 barrels of oil per day
and 1.3 million cubic feet of gas per day. The Company owns a 38%
working interest and a 47.5% net revenue interest in this well due
to its fee land ownership. The Company has successfully completed
four of its first seven 3-D exploratory wells drilled in south
Louisiana.
Gulf of Mexico
Acquisition, processing and interpretation of 3-D seismic
information on its substantial Gulf of Mexico lease inventory
continues to be a focus of activity. In 1994, new 3-D seismic was
acquired covering seven producing areas. Four of the surveys are
in-house and are being evaluated for drilling potential and the
remaining three are expected later this year. An area-wide, multi-
company survey begun in late 1993 has produced 110 blocks of data
so far and another 134 blocks are scheduled for 1995, the second
full year of the program. Total five-year participation in the
program will yield over 500 new blocks of 3-D data.
The Company is also identifying shallower gas targets on
exploratory leases that can be drilled with attractive economics
thereby holding the blocks for later evaluation of their deeper
subsalt potential. During 1994, four such shallow targets were
successfully drilled, thereby protecting those leases from
expiration. Also during 1994, the Company participated in drilling
its first subsalt well at South Timbalier 289. While the well was
plugged and abandoned, geologic information derived from drilling
beneath the salt will be valuable in testing future subsalt
prospects. The Company has identified a number of prospects on its
existing salt-related acreage and expects to participate in
drilling two subsalt wells in 1995.
Participation in the 1994 offshore Louisiana and Texas lease
sales resulted in the acquisition of five new leases covering
24,162 gross and 11,673 net acres.
Algeria
A number of sizeable oil discoveries in 1994 on blocks
immediately adjacent to the Company's Block 405 continue to enhance
the prospectiveness of the Company's acreage. During the year, 380
miles of seismic acquired over the block were processed and
interpreted. A number of prospects and leads were identified. The
site of the first well, the MLE-1, was selected and began drilling
near the end of 1994. A second well is planned for later this
year. In addition to its 712,910 acres on Block 405, the Company
also has a concession on 840,026 acres on Block 215. During 1994,
400 miles of seismic data was processed and interpreted on this
block, yielding additional drilling opportunities. The first well
on Block 215 is expected to be drilled in 1996. Additional seismic
work is planned for Blocks 215 and 405 during 1995. The Company
owns a 65% working interest in both of these areas.
Yemen
Two exploration wells were drilled during 1994 on Block 9
where the Company owns a 17% working interest. Neither of the
wells encountered sufficient hydrocarbons to be commercially
producible. The Company and its partners are reviewing drilling
data from these two wells along with the seismic data acquired to
determine if any additional prospects on the block should be
drilled before the expiration of the concession.
Tunisia
Over 1,700 kilometers of seismic data were acquired in early
1994 over the Company's one million acre Ramla Block, about 80
miles offshore Tunisia in the Gulf of Gabes. Processing of the
data yielded several leads and prospects with the first well
scheduled for drilling by mid-1995. Additional seismic is planned
during the year to evaluate the remaining leads. The Company owns
a 50% working interest in the block.
Other Areas
In Colombia, an unsuccessful exploratory well drilled in 1994
in the Barzalosa Association Contract Area resulted in the Company
relinquishing its concession in that area. However, the general
region remains attractive for exploratory drilling and the Company
acquired a concession in the Bambuco Association Contract Area as
well as a 45% gross working interest in Block 10 in the Llanos
Basin. Seismic studies are planned in each of these areas during
1995 prior to any drilling.
The Company withdrew from three concession areas in Australia
in 1994 based on interpretation of geophysical and geological
studies done over the areas as well as participation in an
unsuccessful exploratory well in one of the blocks. In early 1994,
the Company formed a joint study group with an Australian
exploration company to explore selected areas in Papua New Guinea,
New Zealand as well as offshore Australia. The Company and its
joint group successfully bid a work program in Australia on Block
WA258P located in the Carnarvon Basin. The program commitment
includes seismic acquisition and drilling of one well over a two-
year period. The Company will have a 33.3% interest in the
project.
In Papua New Guinea, the Company is in the process of
improving its acreage position in the prospective highlands area of
the country by restructuring its concession ownership. The Company
awaits ratification of a 43.8% working interest in three contiguous
blocks in the region. Additional geological and geophysical
studies are scheduled for 1995.
During the years 1992 through 1994, LL&E and CLAM participated
in the drilling of exploratory wells with the results set forth in
the table below.
Net wells
Oil Gas Dry
1994 1993 1992 1994 1993 1992 1994 1993 1992
_______________________________________________________________________________________
LL&E and Subsidiaries:
Domestic:
Offshore Gulf of
Mexico - .5 - 3.3 1.8 - 1.8 1.4 1.0
Colorado - - - - - - - - .5
Louisiana 1.2 .7 .4 1.7 1.1 2.2 2.9 1.8 2.5
Wyoming - - - - - - - - .7
North Sea:
United Kingdom .1 .1 - - - - - .1 .1
Other foreign:
Australia - - - - - - .3 .6 -
Canada .5 13.9 12.4 5.3 1.0 .3 2.9 7.4 7.3
Colombia - - .3 - - - 1.0 - -
Egypt - - - - - - - - .2
Yemen - - - - - - .3 - -
_______________________________________________________________________________________
Total 1.8 15.2 13.1 10.3 3.9 2.5 9.2 11.3 12.3
_______________________________________________________________________________________
CLAM (50%)
Netherlands-North Sea - - - - - - .2 .1 .1
_______________________________________________________________________________________
Royalty Interest
During 1994, the following exploratory wells were drilled by
others on LL&E's fee and leasehold acreage.
Gross wells
Oil Gas Dry
_______________________________________________________________________________________
Domestic:
Gulf of Mexico 2 - -
Louisiana 5 3 1
Wyoming - 1 -
Other foreign - Canada 3 - 3
_______________________________________________________________________________________
Total 10 4 4
_______________________________________________________________________________________
DEVELOPMENT ACTIVITIES
Working Interest
Development of the Company's oil and gas properties in 1994
resulted in the expenditures of almost $108 million for
participation in 20 wells and the installation of platforms and
facilities in the United States and overseas. Successful
development drilling resulted in 7 oil and 12 gas wells. In
addition, $2 million was spent in the acquisition of additional
working interests in proved properties in the United States.
Jay Field
At the Jay Field in Florida, a depletion enhancement program
consisting of well workovers and debottlenecking projects has led
to increased production and recoverable reserves from this mature
field. Current gross production averages 16,200 barrels of liquids
per day. In 1995, field partners plan to expand the existing
nitrogen injection program to an area of the field that has not
previously been drained by enhanced recovery. The Company
currently owns a 46% working interest in this field.
Gulf of Mexico
At Eugene Island 217, the "C" platform was installed in
February 1994 and is currently producing 36 million cubic feet of
gas per day and 1,700 barrels of condensate per day from two
successful wells. Another step-out well is expected to add to
producing capacity. The Company owns a 65% working interest in the
property. At Eugene Island 110, a production structure was built,
and pipeline and facilities were installed four months after the
discovery well was drilled. The well tested at 10 million cubic
feet of gas per day and 400 barrels of condensate per day. The
Company owns a 42% working interest in the property. Eugene Island
364 #3, the Company's first operated subsea completion, was put
online in November 1994. Current production is 10 million cubic
feet of gas per day and 400 barrels of condensate per day. This
single well completion is owned 100% by the Company and is tied
back to the Company's Eugene Island 371 "B" platform. Garden Banks
235 #3, the Company's second 100% owned and operated subsea
completion, was also placed on production in November and is
currently producing 20 million cubic feet of gas per day. The well
is in 802 feet of water and is tied back to a platform in shallower
waters at Garden Banks 236. Significant cost savings were achieved
by coordinating the completion of both of these facilities
concurrently.
Four field development projects are currently underway and
scheduled for completion over the next 12 months. At Vermilion
395, where the Company is the operator and owns a 50% working
interest, a new platform will be installed in 428 feet of water by
midyear which will have gross production capacity of 15 million
cubic feet of gas per day. At South Pass 34/47 and Vermilion
143/160, initial production is expected later this year from two
new facilities that will have combined gross production capacity of
70 million cubic feet of gas per day. The Company owns a 50% and
25% working interest in the two projects, respectively. Two
Company-operated platforms to produce four successful exploratory
wells drilled on neighboring blocks South Timbalier 229 and 231 and
Grand Isle 108 during 1994 are being designed with production
startup in early 1996.
Wyoming
Completion of the Lost Cabin Gas Plant will enable the Company
to initiate production in early 1995 from the deep Madison
Formation below 24,000 feet. The Company owns a 37% interest in
the facility. The gross cost of the plant was $83 million and it
initially will process over 50 million cubic feet of gas per day
from two previously-drilled wells to this formation, the Bighorn 1-
5 and the Bighorn 2-3. Plant products include natural gas, sulfur
and carbon dioxide. Production information from these two wells is
key to the further development of this prolific new producing
horizon which can add significant new gas production and reserves.
A third Madison Formation well, the Bighorn 4-36, is expected
to begin drilling in mid-1995. A significant portion of the
Company's cost to drill this well is covered by insurance proceeds
from the blowout of the Bighorn 3-36 well in early 1993. Expansion
of the Lost Cabin Gas Plant to process incremental production from
additional wells drilled to the Madison Formation is under study.
During 1994, sweet gas production from intervals between 5,500
and 18,000 feet averaged 73 million cubic feet of gas per day, the
highest annual average production in the 25-year history of the
field. Deliverability at year-end 1994 was in excess of 85 million
cubic feet of gas per day. This deliverability increase resulted
from the successful drilling of four infill wells and the
completion of 16 workovers of existing wells. Each of these new
wells cost approximately $1 million to drill and complete and
tested at an average rate of 3 million cubic feet of gas per day.
To accommodate this increasing level of production, the Madden gas
gathering system was expanded during 1994.
To assist in the further development of both shallow and deep
gas reserves as well as to generate potential prospects in
undrilled areas of the field, a 3-D seismic survey covering a 37
square mile area of the field was conducted in 1994. By year end,
all field data had been collected and the computer processing and
interpretation of the data had begun.
North Sea
In the U.K. North Sea, annual liquid production volumes from
the Brae complex reached a four-year high during 1994. East Brae,
the largest of the four Brae fields currently producing, went
onstream in late 1993 and reached a peak gross production volume of
110,000 barrels of oil per day in October of 1994. Also during
1994's fourth quarter, the Brae group initiated natural gas sales
at a gross rate 260 million cubic feet of gas per day. Prior to
that time, all gas produced from the complex was reinjected into
the reservoir to optimize liquids recovery. The sales gas is
transported to an onshore processing center at St. Fergus, Scotland
via the SAGE Pipeline System in which the Brae group owns a 50%
equity interest. The Company owns an average 6% working interest
in the Brae complex. The Company's net production of liquid and
gas from Brae ended this year in excess of 13,000 barrels of oil
equivalent per day, an all time high.
The plan of development submitted to the U.K. Department of
Energy for the Beinn gas/condensate field that partially underlies
the North Brae field was approved during 1994. Development costs
for these incremental reserves were reduced substantially because
of the existing Brae production infrastructure. All Beinn
producing wells were completed from the North Brae platform. A
third confirmation well, the 16/7a-B22, was completed in June and
tested 27.7 million cubic feet of gas per day and 3,103 barrels of
condensate per day. Beinn gross liquid production averaged 7,200
barrels of condensate per day during 1994.
The Company owns an 11.26% interest in another U.K. North Sea
producing complex, the T-Block, located just south of the Brae
Field. Two oil fields in the complex, Tiffany and Toni, went on
production from a single platform in late 1993 shortly after the
Company acquired its interest in the property. Production volumes
during 1994 fell below expectations due to continuing mechanical
problems at the Tiffany production platform. A number of these
problems were gradually resolved during the year and gross
production rose steadily, reaching 80,000 barrels of oil per day by
year-end 1994, about 10% below its originally forecast plateau
rate.
The plan of development for two additional T-Block fields,
Thelma and Southeast Thelma, is currently pending and is expected
to be approved during 1995. Using the same subsea technology
employed in the development of the Toni field, both of these new
fields will be tied back to the Tiffany platform utilizing subsea
completions. Initial oil and gas production from the Thelma fields
is expected in 1996.
Indonesia
In the KAKAP Production Sharing Contract offshore in the
Republic of Indonesia, development of the new KG and KRA fields is
continuing. The first three of 14 planned development wells were
recently drilled and await installation of the platform. The
Company's share of KAKAP production will more than double by year-
end 1995 as a result of production sharing from the two new fields.
Development costs of additional reserves and production should be
minimized by utilizing the existing infrastructure in the complex.
During the years 1992 through 1994, LL&E and CLAM participated
in the drilling of development wells with the results set forth in
the table below.
Net wells
Oil Gas Dry
1994 1993 1992 1994 1993 1992 1994 1993 1992
_______________________________________________________________________________________
LL&E and Subsidiaries:
Domestic:
Offshore Gulf of
Mexico .8 1.5 .2 2.3 1.9 1.0 - .3 -
Louisiana - .5 1.6 - - - - - .5
Wyoming - - - .7 1.3 .3 - - -
North Sea:
Netherlands - - .1 .1 - - - - -
United Kingdom .2 .1 .2 - - - .1 - .2
Other foreign-
Colombia - - .3 .1 - - - - -
_______________________________________________________________________________________
Total 1.0 2.1 2.4 3.2 3.2 1.3 .1 .3 .7
_______________________________________________________________________________________
CLAM (50%)
Netherlands-North Sea - - .2 .1 .2 .1 - - -
_______________________________________________________________________________________
Royalty Interest
During 1994, the following development wells were drilled by others on
LL&E's fee and leasehold acreage.
Gross wells
Oil Gas Dry
_______________________________________________________________________________________
Domestic-Louisiana - 1 -
_______________________________________________________________________________________
DRILLING ACTIVITIES AT DECEMBER 31, 1994
Working Interest
The table below sets forth the working interest wells in the
process of drilling at December 31, 1994 by LL&E and by CLAM.
Wells drilling
Gross Net
_______________________________________________________________________________________
LL&E and Subsidiaries:
Domestic 7 3.2
North Sea 4 .6
Other foreign 2 1.0
_______________________________________________________________________________________
Total 13 4.8
_______________________________________________________________________________________
CLAM (50%) Netherlands-North Sea - -
_______________________________________________________________________________________
Royalty Interest
No wells were being drilled by others at December 31, 1994 in
which LL&E has a royalty interest.
OIL AND GAS WELLS
Working Interest
The table below shows the number of productive oil and gas
wells in which working interests are held by LL&E and by CLAM as of
December 31, 1994.
Oil wells Gas wells
Gross Net Gross Net
_______________________________________________________________________________________
LL&E and Subsidiaries:
Domestic 1,384 146.0 314 116.0
North Sea 59 7.6 - -
Other foreign 72 17.4 13 6.7
_______________________________________________________________________________________
Total 1,5151 171.0 3272 122.7
_______________________________________________________________________________________
CLAM (50%) Netherlands-North Sea - - 52 3.7
_______________________________________________________________________________________
1 Includes 44 dual completion wells.
2 Includes 32 dual completion wells.
Royalty Interest
The table below shows the number of productive oil and gas
wells drilled by others in whose production LL&E had a royalty
interest as of December 31, 1994.
Gross wells
Oil Gas
_______________________________________________________________________________________
Domestic 574 206
Other foreign 9 8
_______________________________________________________________________________________
Total 5831 2142
_______________________________________________________________________________________
1 Includes 20 dual completion wells.
2 Includes 9 dual completion wells.
CRUDE AND CONDENSATE, PLANT PRODUCTS AND NATURAL GAS PRODUCTION
AND PRICES REALIZED
The production and average price information for the years
1992 through 1994 are presented under the heading "Oil and Gas
Operating Data" in Part II, Item 8. - "Financial Statements and
Supplementary Data."
Lifting Cost per Equivalent Barrel of Production
The table below presents the average annual production
(lifting) cost per equivalent barrel of production (excluding
royalty interest production) for LL&E and for CLAM for the periods
indicated. For the purpose of this calculation, natural gas and
plant products are converted to equivalent barrels of oil, based on
an estimate of their relative BTU content, at the ratios of 6:1 and
1.56:1, respectively.
1994 1993 1992
_______________________________________________________________________________________
LL&E and Subsidiaries:
Domestic $3.97 4.69 5.51
North Sea 5.89 9.20 7.62
Other foreign 5.59 5.64 5.43
_______________________________________________________________________________________
CLAM
Netherlands-North Sea $2.36 3.07 4.05
_______________________________________________________________________________________
Production (lifting) cost, as defined by the Securities and
Exchange Commission, consists of costs incurred to operate and
maintain wells and related equipment and facilities, as well as
property and production taxes. It does not include depletion,
depreciation, and amortization of capitalized acquisition,
exploration and development costs, general and administrative
expenses, interest expense or income taxes. Accordingly,
production (lifting) cost reflected in the above table does not
represent the total cost involved in producing a barrel of oil.
REFINING OPERATIONS
General
The Company operates a crude oil refinery and terminal in
Mobile, Alabama. Refinery capability consists of the following
units: Atmospheric and Vacuum Distillation, Distillate
Hydrodesulfurization, Sulfur Recovery, Catalytic Reforming and
Light Naphtha Isomerization. This equipment is designed to handle
both high- and low-sulfur feedstocks. The Company's crude oil
terminal is located in Mobile Harbor and can accept vessels up to
35 feet draft. The terminal is connected to the refinery by
parallel crude and product lines (approximately seven miles each in
length) and can accept and load both crude oil and refined
products.
Of the $8.3 million in refinery capital expenditures during
1994, $4.6 million was associated with a vacuum tower upgrade
project and the remainder was related to miscellaneous capital
improvements, safety and environmental items. In 1995, $3 million
has been budgeted for capital projects including $1.5 million
toward profit enhancement and the balance to maintenance, safety
and environmental items.
In 1994, the refinery processed an average of 47,000 barrels
per day of crude oil and remained under the Independent Producers
status during the year. The low industry refinery margins
(excluding retail), which began in 1992, continued through 1994.
Efforts in 1994 were concentrated on cutting feedstock costs and
improving quality, which are expected to improve the refinery's
1995 competitive position.
Sales and Prices Realized
The sales and average price information for the years 1992
through 1994 are presented under the heading "Refining Operating
Data" in Part II, Item 8. - "Financial Statements and Supplementary
Data."
Regulation
FEDERAL ENERGY REGULATORY COMMISSION
Natural gas prices were formerly subject to regulation by the
Federal Energy Regulatory Commission (FERC) pursuant to the Natural
Gas Act of 1938, as amended, and the Natural Gas Policy Act of 1978
(NGPA). Effective December 1, 1978, the NGPA defined certain
categories of natural gas and established price ceilings on all
first sales of gas, whether interstate or intrastate, for most
categories. Price controls on certain categories of gas were
removed on various dates through July 1, 1987.
On July 26, 1989, the Natural Gas Wellhead Decontrol Act of
1989 was enacted. This legislation amended the Natural Gas Policy
Act of 1978, effectively removing wellhead price controls on new
wells or wells not covered by a gas contract immediately and all
maximum lawful price controls by January 1, 1993. As a result of
these legislative acts, none of the Company's natural gas
production is currently subject to wellhead price regulation and
virtually all of it is priced at competitive market levels.
In the winter of 1993-94, FERC implemented its Order 636 on
the comparability of pipeline services. The order was designed to
eliminate certain competitive advantages interstate pipelines may
have had in selling gas and further move the industry toward a more
efficient, competitive market environment. Among other things,
Order 636 required pipelines to unbundle the various services that
they had provided in the past, such as gas supply, gathering,
transmission and storage, and offer these services individually to
their customers. For producers, the net result is expected to be
increased gas sales opportunities.
ENVIRONMENTAL MATTERS
The protection of our environment has always been a
consideration of LL&E and has involved additional operating and
facility costs. As federal, state and local environmental statutes
evolve, LL&E implements design changes and incorporates pollution
control devices at its facilities in response to environmental
considerations. This has impacted the cost of new facilities and
equipment and has been considered a normal, recurring cost of
LL&E's ongoing operations and not an extraordinary cost of
compliance with governmental regulations. LL&E believes that the
amount of presently known expenditures that will be incurred
primarily for environmental controls over the next two to three
years will not have a material adverse effect on its results of
operations, cash flow or financial position. However, as
additional laws or regulations regarding the protection of the
environment are adopted, become effective, or are hereafter
interpreted, there is no assurance that they will not have such an
effect.
As a result of anticipated new regulations promulgated under
the Clean Air Act Amendments of 1990 (CAAA), additional costs may
be incurred at the Company's refining operations and larger
production facilities. These regulations are expected to be
finalized over the next two to five years with implementation
taking effect on a regulatory schedule extending into future years.
Since the Company's operations are located in areas currently
classified as attainment areas for criteria air pollutants, and
most of the Company's operations are below the expected threshold
levels of hazardous air emissions to be regulated, at this time the
Company does not believe that the cost of compliance with the new
CAAA regulations will have a material adverse effect on its results
of operations, cash flow or financial position.
LL&E has received notice from the Environmental Protection
Agency (EPA) that the Company is one of many Potentially
Responsible Parties (PRP) under the Comprehensive Environmental
Response, Compensation and Liability Act, as amended, with respect
to three National Priorities List sites in Abbeville, Louisiana
known as the "D.L. Mud," "Gulf Coast Vacuum" and "PAB Oil and
Chemical" sites. Additionally, in 1993, the Company acquired NERCO
Oil & Gas, Inc. (NERCO), which is also named a PRP at the Gulf
Coast Vacuum and the D.L. Mud sites. With respect to the Gulf
Coast Vacuum site, the Company has entered into a de minimis
Consent Agreement with EPA on behalf of itself and NERCO, which
resolves the Company's and NERCO's liability for remediation of the
site for cash consideration of an immaterial amount. With respect
to D.L. Mud and the PAB Oil and Chemical sites, based on the
Company's evaluation of the potential total cleanup costs, its
estimate of its potential exposure, and the viability of the other
PRPs, the Company believes that any costs ultimately required to be
borne by it at these sites will not have a material adverse effect
on its results of operations, cash flow or financial position.
In view of recent complaints against other oil and gas
companies under the Inventory Update Rule promulgated under the
Toxic Substances Control Act, the Company has investigated its
obligations to report the manufacture and distribution of certain
of its products with respect thereto. As a result of the Company's
investigation, the Company has notified and is meeting with the
appropriate regulatory authorities to resolve its liability, if
any. Based on currently available information, the Company
believes that sanctions, if any, will not have a material adverse
effect on its results of operations, cash flow or financial
position.
ITEM 3. LEGAL PROCEEDINGS.
Information regarding the Company's legal proceedings is
presented in Note 15 under the heading "Notes to Consolidated
Financial Statements" in Part II, Item 8. - "Financial Statements
and Supplementary Data."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
NAME AGE POSITIONS
_________________________________________________________________
H. Leighton Steward (60)
Chairman of the Board, President
and Chief Executive Officer since
1989.
Richard A. Bachmann (50)
Director since 1989. Executive
Vice President, Finance and
Administration and Chief
Financial Officer since 1985.
John F. Greene (54)
Director since 1989. Executive
Vice President, Exploration and
Production since 1985.
Jerry D. Carlisle (49) Vice President and Controller
since 1984.
Robert J. Chebul (47) Vice President since 1991. Held
various managerial positions,
including District Manager from
1988 to 1991.
William N. Hahne (43) Vice President since December
1994. General Manager-Production
from September 1993 to December
1994. Vice President of NERCO
Oil & Gas, Inc. from 1991 to
September 1993. Held various
technical and managerial posi-
tions with Union Texas Petroleum
and Union Oil Company of
California from 1973 to 1991.
John O. Lyles (49)
Vice President since 1992.
Vice President and Treasurer
from 1984 to 1992.
Joel M. Wilkinson (59)
Vice President since 1988.
John A. Williams (50) Vice President since 1988.
Frederick J. Plaeger, II (41)
General Counsel and Corporate
Secretary since 1992. Corporate
Secretary and Senior Counsel from
1989 to 1992.
Louis A. Raspino (43)
Treasurer since 1992. Assistant
Treasurer from 1984 to 1992.
Each officer holds office until the first meeting of the Board
of Directors following the annual meeting of shareholders and
until his successor shall have been elected and qualified, or until
he shall have resigned or been removed as provided in the LL&E By-
Laws. No family relationship exists between any of the above
listed executive officers or between any such executive officer and
any Director of LL&E.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
Information regarding the Company's Capital Stock is presented
under the heading "Capital Stock, Dividends and Other Market Data"
in Item 7. - "Management's Discussion and Analysis of Financial
Condition and Results of Operations." and under the heading "Market
Price and Dividend Data" in Item 8. - "Financial Statements and
Supplementary Data."
ITEM 6. SELECTED FINANCIAL DATA.
The information required hereunder is presented under the
heading "Selected Financial Data" in Item 8. - "Financial
Statements and Supplementary Data."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
The information required hereunder is presented under the
heading "Management's Discussion and Analysis" in Item 8. -
"Financial Statements and Supplementary Data."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The following consolidated financial statements and
supplementary data of the Company are included herein:
Page herein
Financial Statements:
Report of Management 28
Independent Auditors' Report 29
Consolidated Balance Sheets 30
Consolidated Statements of Earnings (Loss) 31
Consolidated Statements of Stockholders' Equity 32
Consolidated Statements of Cash Flows 33
Notes to Consolidated Financial Statements 34
Unaudited Supplemental Data:
Management's Discussion and Analysis 53
Data on Oil and Gas Activities 59
Oil and Gas Operating Data 67
Refining Operating Data 68
Oil and Gas Properties 69
Wells Drilled 70
Selected Financial Data 71
Market Price and Dividend Data 72
Quarterly Data 73
The following financial statements of 50% or less owned persons
required by Regulation S-X, Rule 3-09, are included herein:
Page herein
MaraLou Netherlands Partnership and its wholly owned
consolidated subsidiary, CLAM Petroleum Company:
Independent Auditors' Report 74
Consolidated Balance Sheets 75
Consolidated Statements of Income 76
Consolidated Statements of Partners' Capital 77
Consolidated Statements of Cash Flows 79
Notes to Consolidated Financial Statements 81
_________________________________________________________________
REPORT OF MANAGEMENT
_________________________________________________________________
The consolidated financial statements of The Louisiana Land and
Exploration Company and subsidiaries and the related information
included in this Annual Report have been prepared by Management in
accordance with generally accepted accounting principles and
include certain estimates and judgments which Management considers
appropriate. To meet its responsibilities for the fair
presentation of consolidated financial statements, Management
maintains a system of internal controls, including internal
accounting controls, considered appropriate in view of the costs
associated with the benefits to be derived. In addition, the Audit
Committee meets periodically with the Company's Management, the
internal auditors and KPMG Peat Marwick LLP, independent auditors,
to review and discuss audit activities and results, internal
control procedures and other matters relative to accounting and
financial reporting.
Based on the results of these procedures, Management is of the
opinion that the system of internal controls in effect during the
year ended December 31, 1994 provided reasonable assurance that all
transactions were executed in accordance with Management's
authorizations, that assets were safeguarded from loss and
unauthorized use and that the accounting records and financial
statements properly reflect the transactions of the Company.
H. Leighton Steward Richard A. Bachmann
Chairman, President and Executive Vice President and
Chief Executive Officer Chief Financial Officer
_________________________________________________________________
INDEPENDENT AUDITORS' REPORT
_________________________________________________________________
The Board of Directors and Stockholders
The Louisiana Land and Exploration Company:
We have audited the accompanying consolidated balance sheets of The
Louisiana Land and Exploration Company and subsidiaries as of
December 31, 1994 and 1993, and the related consolidated statements
of earnings (loss), stockholders' equity, and cash flows for each
of the years in the three-year period ended December 31, 1994.
These consolidated financial statements are the responsibility of
the Company's management. Our responsibility is to express an
opinion on these consolidated 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 consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of The Louisiana Land and Exploration Company and
subsidiaries as of December 31, 1994 and 1993, and the results of
their operations and their cash flows for each of the years in the
three-year period ended December 31, 1994 in conformity with
generally accepted accounting principles.
As discussed in Notes 12 and 13 to the consolidated financial
statements, in 1993 the Company adopted the methods of accounting
for income taxes and postretirement benefits other than pensions
prescribed by Statements of Financial Accounting Standards Nos. 109
and 106, respectively. In addition, as discussed in Note 2 to the
consolidated financial statements, in 1994 the Company changed its
methods of assessing the impairment of the capitalized costs of
proved oil and gas properties and other long-lived assets.
/s/ KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
New Orleans, Louisiana
February 3, 1995
_________________________________________________________________________________________
CONSOLIDATED BALANCE SHEETS The Louisiana Land and Exploration
Company and Subsidiaries
December 31, 1994 and 1993
(Millions of dollars)
ASSETS 1994 1993
_________________________________________________________________________________________
CURRENT ASSETS:
Cash, including cash equivalents (1994-$8.6; 1993-$15.5) $ 12.5 33.3
Accounts and notes receivable 126.4 109.7
Income taxes receivable 1.9 5.2
Inventories 31.8 26.8
Prepaid expenses 8.9 12.7
Deferred income taxes 2.6 2.6
_________________________________________________________________________________________
Total current assets 184.1 190.3
_________________________________________________________________________________________
Investments in affiliates 23.4 23.5
Net property, plant and equipment, at cost, under the
successful efforts method of accounting for oil
and gas properties 1,240.4 1,561.0
Other assets 30.2 63.9
_________________________________________________________________________________________
$ 1,478.1 1,838.7
_________________________________________________________________________________________
LIABILITIES AND STOCKHOLDERS' EQUITY
_________________________________________________________________________________________
CURRENT LIABILITIES:
Accounts payable and accrued expenses 187.7 170.9
Income taxes payable 2.8 3.8
_________________________________________________________________________________________
Total current liabilities 190.5 174.7
_________________________________________________________________________________________
Deferred income taxes 40.0 151.2
Long-term debt 739.5 734.5
Other liabilities 155.7 178.5
STOCKHOLDERS' EQUITY:
Capital stock of $.15 par value. Authorized-100,000,000
shares; issued-38,004,537 shares 5.7 5.7
Additional paid-in capital 87.3 82.9
Retained earnings 424.2 684.4
_________________________________________________________________________________________
517.2 773.0
Loans to ESOP (5.2) (8.8)
Cost of capital stock in treasury-4,624,729 shares in
1994 and 4,831,574 shares in 1993 (159.6) (164.4)
_________________________________________________________________________________________
TOTAL STOCKHOLDERS' EQUITY 352.4 599.8
_________________________________________________________________________________________
$ 1,478.1 1,838.7
_________________________________________________________________________________________
See accompanying notes to consolidated financial statements.
_________________________________________________________________________________________
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) The Louisiana Land and Exploration
Company and Subsidiaries
Years ended December 31, 1994, 1993 and 1992
(Millions, except per share data)
1994 1993 1992
_________________________________________________________________________________________
REVENUES:
Oil and gas $ 421.2 370.1 323.9
Refined products 361.3 400.2 441.9
Gain on sales of oil and gas properties 6.8 23.5 -
Other (interest, 1994-$1.6; 1993-$3.4; 1992-$3.6) 12.2 21.6 21.6
_________________________________________________________________________________________
801.5 815.4 787.4
_________________________________________________________________________________________
COSTS AND EXPENSES:
Lease operating and facility expenses 116.1 106.8 98.5
Refinery cost of sales and operating expenses 354.5 403.4 424.3
Dry holes and exploratory charges 69.7 48.8 41.5
Depletion, depreciation and amortization 202.2 129.8 106.5
Taxes, other than on earnings 25.4 24.7 24.4
General, administrative and other expenses 44.6 49.0 42.3
Interest and debt expenses 25.6 28.3 24.6
Restructuring charges - - 52.4
Reversal of litigation accrual (10.0) - (25.0)
Write-down of petroleum assets 319.0 - -
_________________________________________________________________________________________
1,147.1 790.8 789.5
_________________________________________________________________________________________
Earnings (loss) before income taxes (345.6) 24.6 (2.1)
Income tax expense (benefit) (118.7) 11.9 (.9)
_________________________________________________________________________________________
Earnings (loss) before extraordinary
item and cumulative effect of changes
in accounting principles (226.9) 12.7 (1.2)
Extraordinary item: loss on early retirement
of debt - (3.3) (5.6)
Cumulative effect on years prior to 1993
of change in accounting principle for
income taxes - 13.7 -
Cumulative effect on years prior to 1993
of change in accounting principle for
postretirement benefits other than
pensions - (13.5) -
_________________________________________________________________________________________
NET EARNINGS (LOSS) $ (226.9) 9.6 (6.8)
_________________________________________________________________________________________
Primary and fully diluted earnings (loss) per
share before extraordinary item and cumulative
effect of changes in accounting principles (6.80) 0.43 (0.04)
Extraordinary item: loss on early retirement
of debt - (0.11) (0.20)
Change in accounting principle for income taxes - 0.47 -
Change in accounting principle for post-
retirement benefits - (0.46) -
_________________________________________________________________________________________
PRIMARY AND FULLY DILUTED EARNINGS (LOSS) PER SHARE $ (6.80) 0.33 (0.24)
_________________________________________________________________________________________
AVERAGE SHARES 33.4 29.5 28.4
_________________________________________________________________________________________
See accompanying notes to consolidated financial statements.
/TABLE
________________________________________________________________________________________
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY The Louisiana Land and Exploration
Company and Subsidiaries
Years ended December 31, 1994, 1993 and 1992
(Millions of dollars, except per share data)
Additional Treasury stock
paid-in Retained Loans to Number of
capital earnings ESOP shares Cost
_________________________________________________________________________________________
Balance at December 31, 1991 $41.3 $739.6 $(14.8) 9,718,025 $(325.3)
Net loss - (6.8) - - -
Cash dividends ($1.00 per
share) - (28.3) - - -
Repayment of loans to ESOP - - 3.0 - -
Other .2 - - (61,858) 2.0
_________________________________________________________________________________________
Balance at December 31, 1992 41.5 704.5 (11.8) 9,656,167 (323.3)
Net earnings - 9.6 - - -
Sale of treasury stock 40.7 - - (4,400,000) 148.1
Cash dividends ($1.00 per
share) - (29.8) - - -
Repayment of loans to ESOP - - 3.0 - -
Purchase of treasury stock - - - 40,247 (1.5)
Other .7 .1 - (464,840) 12.3
_________________________________________________________________________________________
Balance at December 31, 1993 82.9 684.4 (8.8) 4,831,574 (164.4)
Net loss - (226.9) - - -
Cash dividends ($1.00 per
share) - (33.3) - - -
Repayment of loans to ESOP - - 3.6 - -
Other 4.4 - - (206,845) 4.8
_________________________________________________________________________________________
Balance at December 31, 1994 $87.3 $424.2 $ (5.2) 4,624,729 $(159.6)
_________________________________________________________________________________________
Capital stock of $.15 par value was unchanged during the three-year period ended December
31, 1994.
See accompanying notes to consolidated financial statements.
_________________________________________________________________________________________
CONSOLIDATED STATEMENTS OF CASH FLOWS The Louisiana Land and Exploration
Company and Subsidiaries
Years ended December 31, 1994, 1993 and 1992
(Millions of dollars)
1994 1993 1992
_________________________________________________________________________________________
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $(226.9) 9.6 (6.8)
Adjustments to reconcile to cash flows from
operations:
Write-down of petroleum assets 319.0 - -
Changes in accounting principles, net - (.2) -
Gain on sales of oil and gas properties (6.8) (23.5) -
Restructuring charges - - 52.4
Extraordinary item: loss on early
retirement of debt - 3.3 5.6
Depletion, depreciation and amortization 202.2 129.8 106.5
Deferred income taxes (111.2) 9.2 5.0
Dry holes and impairment charges 36.4 21.8 19.2
Other 2.2 22.2 5.8
_________________________________________________________________________________________
214.9 172.2 187.7
Changes in operating assets and liabilities,
net of acquisitions:
Net (increase) decrease in receivables (9.0) 4.3 44.8
Net increase in inventories (5.0) (4.9) (1.8)
Net (increase) decrease in prepaid items 3.8 (5.0) 3.4
Net increase (decrease) in payables .7 2.7 (52.0)
Other 6.7 9.6 (3.4)
_________________________________________________________________________________________
Net cash flows from operating activities 212.1 178.9 178.7
_________________________________________________________________________________________
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions - (547.9) -
Capital expenditures (236.8) (171.7) (153.8)
Proceeds from asset sales 15.6 43.7 48.5
Other (16.3) (46.4) (11.0)
_________________________________________________________________________________________
Net cash flows from investing activities (237.5) (722.3) (116.3)
_________________________________________________________________________________________
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of treasury stock - 188.8 -
Additions to long-term debt 239.7 492.0 100.0
Repayments of long-term debt (234.7) (104.6) (116.8)
Dividends (33.3) (29.8) (28.3)
Advances against cash surrender value 34.4 - -
Repayment of loans to ESOP 3.6 3.0 3.0
Purchase of treasury stock - (1.5) -
Other (5.1) (11.7) (6.5)
_________________________________________________________________________________________
Net cash flows from financing activities 4.6 536.2 (48.6)
_________________________________________________________________________________________
Increase (decrease) in cash and cash equivalents $ (20.8) (7.2) 13.8
_________________________________________________________________________________________
See accompanying notes to consolidated financial statements.
/TABLE
_________________________________________________________________
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Louisiana Land
and Exploration
Company and
Subsidiaries
December 31, 1994, 1993 and 1992
_________________________________________________________________
1. Summary of Significant Accounting Policies
a. Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its subsidiaries. All significant intercompany
transactions and balances have been eliminated in consolidation.
Investments in affiliates are accounted for under the equity
method. Certain amounts have been reclassified to conform to the
current period's presentation.
b. Petroleum Operations
The Company uses the successful efforts method of accounting for
its oil and gas operations. The costs of unproved leaseholds are
capitalized pending the results of exploration efforts.
Significant unproved leasehold costs are assessed periodically, on
a property-by-property basis, and a loss is recognized to the
extent, if any, that the cost of the property has been impaired.
The costs of individually insignificant unproved leaseholds
estimated to be nonproductive are amortized over estimated holding
periods based on historical experience. The Company assesses the
impairment of capitalized costs of proved oil and gas properties by
comparing net capitalized costs to undiscounted future net cash
flows after estimated income taxes on a field-by-field basis using
period-end prices. For measurement purposes, future net cash flows
are determined using period-end prices adjusted for changes in
prices as of the date of the auditors' report on the Company's
consoli-dated financial statements. Exploratory dry holes and
geological and geophysical charges are expensed. Depletion of
proved leaseholds and amortization and depreciation of the costs of
all development and successful exploratory drilling are provided
by the unit-of-production method based upon estimates of proved and
proved-developed oil and gas reserves, respectively, for each
property. The estimated costs of dismantling and abandoning
offshore and significant onshore facilities are provided currently
using the unit-of-production method; such costs for other onshore
facilities are insignificant and are expensed as incurred. The
costs of refining and processing equipment and facilities are
depreciated on a straight-line basis over their estimated useful
lives.
The Company uses the entitlement method for recording natural gas
sales revenues. Under the entitlement method of accounting,
revenue is recorded based on the Company's net working interest in
field production. Deliveries of natural gas in excess of the
Company's working interest are recorded as liabilities while under-
deliveries are recorded as receivables. Such amounts are
immaterial.
c. Financial Instruments and Hedging Activities
The Company's anticipated refinery purchases of crude oil and sales
of refined petroleum products and its committed British pound
currency expenditures are periodically hedged against market risks
through the use of forward/futures contracts. The gains and losses
on these contracts are included in the valuation of the
transactions being hedged. The Company also manages the interest
rate components of its debt portfolio through the use of swap
agreements. Gains and losses on swap agreements are accrued to
interest expense on a monthly basis over the terms of the
agreements.
d. Functional Currency
The foreign exploration and production operations of the Company's
subsidiaries and its foreign affiliate, CLAM Petroleum Company, are
considered an extension of the parent company's operations. The
assets, liabilities and operations of these companies are therefore
measured using the United States dollar as the functional currency.
As a result, foreign currency translation/transaction adjustments
(which were not material) are included in net earnings.
e. Income Taxes
The Company and its domestic subsidiaries file a consolidated
federal income tax return. In 1993, Statement of Financial
Accounting Standards No. 109 (SFAS No. 109) - "Accounting for
Income Taxes" was adopted effective as of January 1, 1993. The
Company applied the provisions of the SFAS No. 109 without
restating prior years' financial statements. For the Company, the
most significant change in SFAS No. 109 is that deferred tax assets
are initially recognized (i) for differences between the financial
statement carrying amounts and tax bases of assets and liabilities
that will result in future deductible amounts and (ii) for
operating loss and tax credit carryforwards. A valuation allowance
would then be established to reduce that deferred tax asset if it
is more likely than not that the related tax benefits will not be
realized. Previously, the recognition of deferred tax benefits was
limited to benefits that would offset deferred tax liabilities and
benefits that could be realized through carryback to recover taxes
paid for the current year or prior years.
f. Earnings (Loss) Per Share
Primary earnings (loss) per share are calculated on the weighted
average number of shares outstanding during each period for capital
stock and, when dilutive, capital stock equivalents, which assumes
exercise of stock options. Fully diluted earnings (loss) per share
are calculated on the same basis, but also assumes conversion, when
dilutive, of the convertible subordinated debentures for the period
outstanding prior to the call for redemption on September 25, 1992,
and elimination of the related interest expense, net of income
taxes.
2. Write-down of Petroleum Assets
In the fourth quarter of 1994, the Company changed its method of
periodically assessing the impairment of capitalized costs of
proved oil and gas properties. Historically, this assessment has
been determined by comparing the total capitalized costs of oil and
gas properties less accumulated depletion, depreciation and
amortization and related deferred income taxes (net capitalized
costs) to undiscounted future net cash flows of proved oil and gas
reserves after estimated income taxes. Under the revised method,
the Company assesses impairment by comparing net capitalized costs
to undiscounted future net cash flows after estimated income taxes
on a field-by-field basis using period-end prices. For measurement
purposes, future net cash flows are determined using period-end
prices adjusted for changes in prices as of the date of the
auditors' report on the Company's consolidated financial
statements. Prices utilized for measurement purposes and expected
costs are held constant. As a result of the change in method, the
Company reduced the capitalized costs of its oil and gas properties
by a fourth quarter charge against earnings of approximately $280
million (before income tax benefits of $95 million).
In addition, the Company changed its method of measuring the
impairment of other long-lived assets, specifically facilities,
from a measurement based upon undiscounted future net cash flows to
a measurement based upon fair value for assets where it is
determined that net capitalized costs exceed undiscounted future
net cash flows. As a result of this change, the Company reduced
the capitalized costs of its refinery assets by a fourth quarter
charge against earnings of $39 million (before income tax benefits
of $13.7 million).
The Company believes that the changes discussed above are
preferable because they better reflect, on a more current basis,
the impact of changes in the financial components inherent in the
calculation of the impairment of capitalized costs of proved
petroleum properties and other long-lived assets. Because the
above are changes in accounting estimates recognized in whole or in
part by changes in accounting principles, the effects are reported
as part of earnings (losses) before income taxes.
3. Property Acquisitions and Dispositions
Acquisitions
In September 1993, the Company completed the acquisition of all of
the issued and outstanding common stock of NERCO Oil & Gas, Inc.
(NERCO) for a cash purchase price of approximately $354 million
plus associated expenses. The acquisition was financed initially
through the credit facility discussed in Note 10. The cost of the
acquisition was allocated under the purchase method of accounting
based on the fair value of the assets acquired and liabilities
assumed.
The results of NERCO's operations were consolidated with the
Company's effective October 1, 1993. Pro forma combined results of
operations of the Company and NERCO, including appropriate purchase
accounting adjustments for the years ending December 31, 1993 and
1992, as though the acquisition had taken place on January 1 of the
respective years, are as follows:
(Millions of dollars, except per share data) 1993 1992
________________________________________________________________________________________
Revenues $ 907.1 926.1
________________________________________________________________________________________
Earnings (loss) before extraordinary items and cumulative effect
of changes in accounting principles (.3) (11.5)
________________________________________________________________________________________
Net earnings (loss) (3.4) (17.1)
________________________________________________________________________________________
Primary and fully diluted earnings (loss) per share $ (0.09) (0.53)
________________________________________________________________________________________
In December 1993, the Company acquired an 11.26% working interest
in Block 16/17 in the U.K. North Sea (T-Block) from British Gas
Exploration and Production Limited for approximately $187 million
in cash. The purchase was financed initially through the credit
facility discussed in Note 10. Initial production from T-Block
came onstream in late 1993 and had an insignificant impact on
results of operations.
Dispositions
In 1994, the Company sold various domestic oil and gas producing
properties for approximately $15 million resulting in a gain of
$6.8 million (before income taxes of $2.3 million).
In December 1993, the Company completed the sale of certain oil and
gas producing properties, undeveloped acreage and seismic data
located in southern Alberta, Canada for approximately $42.8 million
resulting in a gain, net of associated expenses, of approximately
$23.5 million (before income taxes of $10.3 million). The
properties sold generated revenues of $12.1 million and $15.3
million and pretax earnings of $1.2 million and $1.6 million in
1993 and 1992, respectively.
4. Cash Flows
All of the Company's cash investments are liquid short-term debt
instruments and are considered to be cash equivalents. These cash
investments are carried in the accompanying balance sheets at cost
plus accrued interest, which approximates fair value. Cash flows
related to hedging activities through forward/futures contracts are
classified in the same categories as that from the items being
hedged.
In 1992, the Company acquired certain proved properties for
approximately $36 million and incurred a short-term liability which
was outstanding at year end, the settlement of which is included in
1993 cash flows from investing activities.
5. Restructuring and Other Nonrecurring Charges/Credits
As reported in prior years, the State of Louisiana had asserted
claims against the Company in its capacity as sublessor to Texaco
of certain State leases, based upon Texaco's alleged royalty
miscalculations. In February 1994, a settlement was agreed to by
all parties. The amounts previously provided in the financial
statements for this litigation exceeded the cash payment required
by $10 million, which was reversed during the first quarter of
1994. In the first quarter of 1992, the Company had similarly
reduced its litigation accrual for the State of Louisiana gas
royalty claim by $25 million. These adjustments to the litigation
accrual are included in "Net increase (decrease) in payables" in
the accompanying Consolidated Statements of Cash Flows.
In the first quarter of 1992, the Company recorded a charge of
$52.4 million (before income tax benefits of approximately $17.8
million) against earnings to provide for the restructuring of its
oil and gas operations. This charge included provisions for
estimated losses on the disposition of selected domestic properties
of $47.6 million (both developed and undeveloped) and costs
associated with staff retirements, reductions and related
transition expenses of $4.8 million. These charges were reduced by
the aforementioned $25 million reduction in a litigation accrual.
The Company completed the sale of substantially all of the selected
properties for a purchase price of $48.1 million in the third
quarter of 1992 resulting in a gain of approximately $8 million
which was applied against the restructuring charges.
6. Inventories
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Refinery inventories at lower of (last-in,
first-out) cost or market $30.8 24.1
Repair parts, supplies and other, at lower of
average cost or market 1.0 2.7
_________________________________________________________________________________________
$31.8 26.8
_________________________________________________________________________________________
At December 31, 1993, the LIFO cost of refinery inventories
exceeded their current market values which resulted in a non-cash
charge to earnings of $6.5 million (before income tax benefits of
$2.3 million) which is included in "Refinery cost of sales and
operating expenses" in the accompanying Consolidated Statements of
Earnings (Loss).
7. Investments in Affiliates
Investment
% (Millions of dollars)
Investee Industry Location Owned 1994 1993
_________________________________________________________________________________________
MaraLou (CLAM
Petroleum Oil &
Company) Gas North Sea 50% $18.9 20.8
Other Various U.S. Various 4.5 2.7
_________________________________________________________________________________________
$23.4 23.5
_________________________________________________________________________________________
The Company's equity in earnings of affiliates, which is included
in "Other revenues" in the accompanying Consolidated Statements of
Earnings (Loss), amounted to $4.2 million, $2.4 million and $6.9
million in 1994, 1993 and 1992, respectively. Cash dividends
received from MaraLou/CLAM in 1994, 1993 and 1992 totaled $6
million, $10 million and $7.5 million, respectively.
The consolidated financial position of MaraLou and its wholly owned
subsidiary, CLAM, as of December 31, 1994 and 1993 and the results
of their operations for each of the years in the three-year period
ended December 31, 1994 are summarized below.
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Current assets $ 24.0 28.0
_________________________________________________________________________________________
Noncurrent assets 175.3 170.8
_________________________________________________________________________________________
Current liabilities 15.8 30.2
_________________________________________________________________________________________
Noncurrent liabilities 145.7 127.0
_________________________________________________________________________________________
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Gross revenues $ 68.7 61.1 82.9
_________________________________________________________________________________________
Operating profit 36.2 30.1 42.4
_________________________________________________________________________________________
Earnings before cumulative effect of
change in accounting principle 8.2 10.9 13.8
_________________________________________________________________________________________
Net earnings 8.2 4.9 13.8
_________________________________________________________________________________________
MaraLou applied the provisions of SFAS No. 109 as of January 1,
1993 without restating prior years' financial statements. Upon
adoption, MaraLou recorded a non-cash charge to earnings of $6
million ($3 million net to the Company's interest).
The common stock of CLAM is pledged as collateral under a revolving
credit agreement between MaraLou and a group of banks. The credit
agreement is nonrecourse to the partners of MaraLou.
8. Property, Plant and Equipment
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Petroleum properties:
Proved $2,530.3 2,507.2
Unproved 170.6 127.5
Refining and marketing 276.6 242.8
_________________________________________________________________________________________
2,977.5 2,877.5
Other properties 72.4 69.0
_________________________________________________________________________________________
3,049.9 2,946.5
Less accumulated depletion, depreciation and amortization 1,809.5 1,385.5
_________________________________________________________________________________________
$1,240.4 1,561.0
_________________________________________________________________________________________
9. Financial Instruments and Hedging Activities
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. They are
used solely to manage well-defined interest rate, foreign currency
and commodity price risks.
At December 31, 1994, the Company had $100 million of notional
value interest rate swap agreements terminating in 1997; none were
in place at the end of 1993 (see Note 11). These agreements allow
the Company to manage fixed- and variable-rate interest exposure by
converting a portion of the Company's fixed-rate exposure to
variable rate. The fair value of the interest rate swap agreements
at December 31, 1994 amounted to $4.7 million, which represents the
Company's cost to terminate the agreements. The Company also had
$11.7 million of British pound currency forward contracts maturing
from 1995 through 1997. Such contracts totaled $24.6 million at
December 31, 1993. These contracts lock-in the exchange rate for
a portion of the British pounds needed to fund the Company's future
expenditures in the North Sea. British pound currency forward
contracts are valued at the net benefit or cost to the Company to
unwind its forward position, which was estimated to be a benefit of
$.7 million and a cost of $1 million at December 31, 1994 and 1993,
respectively.
The carrying amounts of cash and cash equivalents and long-term,
variable-rate debt approximate fair value. The Company estimates
the fair value of its long-term, fixed-rate debt as $353 million
and $546 million at December 31, 1994 and 1993, respectively, based
upon quoted market prices for the same or similar issues. Such
debt was recorded at carrying values of $400 million and $533
million, resulting in an unrealized gain of $47 million and an
unrealized loss of $13 million for the respective periods.
The Company also used futures, forwards, options and swap contracts
to reduce price volatility of refinery feedstock and the sale of
refined products produced therefrom. Although generally settled in
cash, these contracts permit settlement by delivery of commodities.
At December 31, 1994, the Company had contracts maturing monthly
through November 1995 covering the net purchase of 1.4 million
barrels of feedstock totaling $25.5 million and the net sale of 1.4
million barrels of refined products totaling $30.1 million. Gains
or losses resulting from market changes will be offset by losses or
gains on the Company's hedged inventory or production. The Company
processed over 17 million barrels of crude oil and sold more than
19 million barrels of refined products in 1994 and had
approximately 1.9 million barrels of crude oil and petroleum
products in its refinery inventories at December 31, 1994.
These financial instruments are generally executed on the New York
Mercantile Exchange or with major financial or commodities trading
institutions which, along with cash and cash equivalents and
accounts receivable, expose the Company to acceptable levels of
market and credit risks and may at times be concentrated with
certain counterparties or groups of counterparties. The credit
worthiness of counterparties is subject to continuing review and
full performance is anticipated.
10. Long-term Debt
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Revolving Credit Facility $ 64.0 160.0
7-5/8% Debentures due 2013 100.0 100.0
7.65% Debentures due 2023 200.0 200.0
Term Loan with banks - 133.5
8-1/4% Notes due 2002 100.0 100.0
Commercial paper notes 271.7 32.0
Notes payable to bank for financing of leveraged ESOP 3.5 8.8
Other issues .3 .2
_________________________________________________________________________________________
Total long-term debt $739.5 734.5
_________________________________________________________________________________________
Debt maturities for the next five years follows:
(Millions of dollars)
_________________________________________________________________________________________
1995 $ -
_________________________________________________________________________________________
1996 29.2
_________________________________________________________________________________________
1997 80.0
_________________________________________________________________________________________
1998 80.0
_________________________________________________________________________________________
1999 80.0
_________________________________________________________________________________________
To finance the aforementioned NERCO and T-Block acquisitions (see
Note 3), refinance certain existing indebtedness and fund general
corporate activities, the Company entered into a $790 million
credit facility with a syndicate of banks in September 1993.
Commitments under the agreement originally consisted of (i) a $540
million revolving credit facility and (ii) a $250 million term loan
facility (which was utilized and repaid and is no longer available
to the Company). The revolving credit facility, which was
subsequently reduced to $450 million, was renegotiated in 1994 and
converted to a reducing revolving loan. The commitments will be
reduced by $20 million quarterly from June 1995 through September
2000. Amounts outstanding under the revolving credit facility bear
interest at fluctuating rates subject to certain options chosen in
advance by the Company. Borrowings under the facility in 1994 were
at an average interest rate of 4.8%. Borrowings under the
revolving credit facility and the term loan facility during 1993
were at average interest rates of 5%. Fees ranging from .125% to
.30%, based upon financial tests, debt ratings and subject to
certain options chosen by the Company, are charged on the facility.
In June 1992, the Company registered under the Securities and
Exchange Commission's shelf registration rules $300 million of
senior unsecured debt securities to be issued from time to time on
terms to be then determined. In June 1992, the Company sold $100
million of 8-1/4% Notes due 2002. In April 1993, the Company
completed its second $100 million public offering of debt
securities under the existing shelf registration filed in 1992 with
the issuance of 7-5/8% Debentures due 2013. In November 1993, the
Company registered up to $500 million of senior unsecured debt
securities under the Securities and Exchange Commission's shelf
registration rules, which included the $100 million available under
the shelf registration filed in 1992. In December 1993, the
Company completed a $200 million public offering with the issuance
of 7.65% Debentures due 2023.
In 1987 and 1988, the Company borrowed $10.2 million and $14
million, respectively, from a bank (unsecured) and loaned the
proceeds to the leveraged employee stock ownership plan (ESOP) to
fund its purchases of 836,368 shares of Company capital stock. The
loans to the ESOP are secured by the Company's capital stock owned
by the ESOP. The interest rates vary with time and market
conditions and are determined by the bank subject to certain
options chosen in advance by the Company. The average interest
rates for both loans in 1994 and 1993 were 4% and 3.1%,
respectively.
During 1994, the average monthly balance of commercial paper notes
outstanding was $118 million; the maximum amount outstanding during
that period was $301 million. Commercial paper borrowings during
1994 and 1993 were at average interest rates of 4.6% and 3.3%,
respectively. The commercial paper program is supported by the
unused portion of the aforementioned revolving credit facility.
The Term Loan with banks, which was retired in January 1994, was
unsecured and was payable in July 1994. The balance was excluded
from current liabilities as the Company refinanced the balance due
on a long-term basis utilizing the revolving credit facility. The
early retirement, completed at a price of 102.4% of principal, and
the premium, along with unamortized discount, resulted in an
extraordinary loss of $3.3 million, after income tax benefits of
$1.7 million. In September 1992, the Company announced the call
for early retirement of the 8-1/2% Convertible Subordinated
Debentures due September 2000. The redemption, completed at a
price of 101.66% of principal, and the premium, along with
unamortized discount, resulted in an extraordinary loss of $5.6
million, after income tax benefits of $2.8 million.
11. Interest and Debt Expenses
For the years ended December 31, 1994, 1993 and 1992, interest
costs incurred, which were essentially the same as interest
payments, were $47.9 million, $47 million and $37.5 million,
respectively, of which $22.3 million, $18.7 million and $12.9
million, respectively, were capitalized as part of the cost of
property, plant and equipment.
In connection with the credit facility discussed in Note 10, bank
fees and other costs totaled $8.1 million of which $6.7 million was
charged to interest and debt expenses in the fourth quarter of
1993.
In 1992 and 1993, the Company participated in interest rate swaps
(which were to terminate in 1994 and 1996, respectively) having a
notional principal amount totaling $200 million. Under the
agreements, the Company received an annual fixed rate and paid a
variable rate based on the six-month London Interbank Offered Rate.
In September 1993, the Company terminated both agreements and
deferred a gain of approximately $3.6 million which will be
recognized over the remaining terms of the respective agreements as
reductions of interest expense.
12. Income Taxes
As explained in Note 1(e), the Company adopted SFAS No. 109
effective January 1, 1993. Upon adoption, the Company recorded a
non-cash credit to earnings in the first quarter of 1993 of $13.7
million which represented the recognition of deferred tax assets
existing at December 31, 1992.
With the enactment of the Budget Reconciliation Act of 1993, the
Federal statutory corporate income tax rate was increased from 34%
to 35% retroactive to January 1, 1993. As a result, the Company
increased its deferred income tax liabilities as of January 1, 1993
with a non-cash charge to income tax expense of $3 million in the
third quarter of 1993.
The components of earnings (loss) before income taxes were taxed
under the following jurisdictions:
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Domestic $(322.0) 9.7 (15.9)
Foreign (23.6) 14.9 13.8
_________________________________________________________________________________________
$(345.6) 24.6 (2.1)
_________________________________________________________________________________________
Components of income tax expense (benefit) are as follows:
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Current tax expense (benefit):
Federal $ (3.5) (3.5) (7.3)
State (.7) (.3) .1
Foreign (3.3) 6.5 1.3
_________________________________________________________________________________________
(7.5) 2.7 (5.9)
_________________________________________________________________________________________
Deferred tax expense (benefit):
Federal (109.2) 9.2 3.8
Foreign (2.0) - 1.2
_________________________________________________________________________________________
(111.2) 9.2 5.0
_________________________________________________________________________________________
$(118.7) 11.9 (.9)
_________________________________________________________________________________________
Tax expense (benefit) differs from the amounts computed by applying
the U.S. Federal tax rate (1994-93 - 35%; 1992 - 34%) to earnings
(loss) before income tax. The reasons for the differences are as
follows:
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Computed "expected" tax expense (benefit) $(121.0) 8.6 (.7)
Increases (reductions) in taxes resulting from:
Increase in Federal income tax rate - 3.0 -
Equity in earnings of foreign affiliates 4.5 (7.4) (1.3)
Foreign income taxes, net of Federal income tax
benefit (2.0) 8.4 3.1
Employee benefit plans (1.1) (.9) (1.2)
Percentage depletion (.2) (.1) (.3)
Other 1.1 .3 (.5)
_________________________________________________________________________________________
$(118.7) 11.9 (.9)
_________________________________________________________________________________________
As a result of the prospective adoption of SFAS No. 109 effective
January 1, 1993, the following additional disclosures are presented
as of and for the years ended December 31, 1994 and 1993.
Total income tax expense (benefit) was allocated as follows:
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Income (loss) before extraordinary item and changes in
accounting principles $(118.7) 11.9
Loss on early retirement of debt - (1.7)
Change in accounting principle for income taxes - (13.7)
Change in accounting principle for postretirement benefits - (7.0)
Stockholders' equity for compensation expense for tax purposes
in excess of amount recognized for financial reporting purposes (1.0) (1.8)
_________________________________________________________________________________________
$ (119.7) (12.3)
_________________________________________________________________________________________
The significant components of income tax expense (benefit) attri-
butable to income from continuing operations are as follows:
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Current tax expense (benefit) $ (7.5) 2.7
Deferred tax expense (benefit) (exclusive of the effects
of other components listed below) (2.5) 6.2
Deferred tax benefits related to write-down of petroleum
assets (108.7) -
Adjustments to deferred tax assets and liabilities for increase in
Federal income tax rate - 3.0
_________________________________________________________________________________________
$(118.7) 11.9
_________________________________________________________________________________________
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities are as follows:
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Deferred tax assets:
Deferred foreign tax credits $ 32.3 22.8
Foreign tax credit carryforwards 11.7 10.2
Federal net operating loss carryforwards 36.4 -
Alternative minimum tax credit carryforward 1.9 5.2
Employee benefits 19.0 18.7
Other 10.3 12.8
_________________________________________________________________________________________
Total gross deferred tax assets 111.6 69.7
Less valuation allowance (28.3) (17.8)
_________________________________________________________________________________________
Net deferred tax assets 83.3 51.9
_________________________________________________________________________________________
Deferred tax liabilities:
Property, plant and equipment, principally due to differences in
depreciation and capitalized interest (90.7) (178.7)
Other (30.0) (21.8)
_________________________________________________________________________________________
Total gross deferred tax liabilities (120.7) (200.5)
_________________________________________________________________________________________
$ (37.4) (148.6)
_________________________________________________________________________________________
The net changes in the valuation allowance for the years ended
December 31, 1994 and 1993 were increases of $10.5 million and $3
million, respectively. These changes were made to provide for
uncertainties surrounding the realization of certain foreign tax
credit carryforwards. The remaining balance of the deferred tax
assets should be realized through future operating results and the
reversal of taxable temporary differences.
Deferred tax expense (benefit) included the following components,
the disclosure of which was prescribed by the prior standard:
(Millions of dollars) 1992
_________________________________________________________________________________________
Restructuring and other special charges/credits $ (1.8)
Intangible development and exploration costs 10.1
Interest 2.2
Depreciation (9.8)
Depletion .7
Foreign taxes 1.2
Equity in earnings of affiliates (.4)
Alternative minimum tax credit carryforward 2.2
Employee benefit plans .1
Partnerships -
Other .5
_________________________________________________________________________________________
$ 5.0
_________________________________________________________________________________________
For the years ended December 31, 1994, 1993 and 1992, the Company's
net cash payments (refunds) of income taxes totaled $(1.1) million,
$7.1 million and $(.6) million, respectively.
At December 31, 1994, the Company has foreign tax credit
carryforwards for Federal income tax purposes of $11.7 million
which are available through 1997 to offset future Federal income
taxes, if any. The Company has Federal net operating loss
carryforwards totaling $103.9 million which are available to offset
future Federal taxable income through 2009. The Company also has
alternative minimum tax credit carryforwards of $1.9 million which
are available to reduce Federal regular income taxes, if any, over
an indefinite period.
13. Retirement Benefits
The Company has a noncontributory defined benefit pension plan
covering all eligible employees, with benefits based on years of
service and the employee's highest three-year average monthly
earnings. The Company's funding policy is intended to provide for
both benefits attributed to service to-date and for those expected
to be earned in the future. Plan assets consist primarily of
stocks, bonds and short-term cash investments, including 51,971
shares of Company capital stock as of December 31, 1994 and 1993
with market values of $1.9 million and $2.1 million, respectively.
Since the spin-off of the pension plan of a discontinued subsidiary
in 1985 and the contribution of excess assets remaining after
purchasing annuities for affected employees, the pension plan did
not require funding through the year ended December 31, 1992.
Funding requirements for the years ended December 31, 1994 and 1993
amounted to $5.5 million and $4.2 million, respectively.
The following tables set forth the plan's funded status and amounts
recognized in the statements of financial position and results of
operations at December 31:
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Accumulated benefit obligation, including vested benefits
of $16.1 and $16.8 $ 16.8 17.6
_________________________________________________________________________________________
Projected benefit obligation (25.5) (27.1)
Plan assets at fair market value 17.5 13.0
_________________________________________________________________________________________
Plan assets under projected benefit obligation (8.0) (14.1)
Additional minimum liability - (2.8)
Unrecognized net loss from past experience different
from that assumed and effects of changes in assumptions 9.3 13.5
Unrecognized net asset being recognized over 15 years (1.0) (1.2)
_________________________________________________________________________________________
Prepaid (accrued) pension cost $ .3 (4.6)
_________________________________________________________________________________________
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Service cost $ 3.4 1.8 1.6
Interest cost 2.0 1.4 1.3
Actual (gain) loss on plan assets .4 (1.3) (1.1)
Net amortization and deferral (1.1) .1 (.6)
_________________________________________________________________________________________
Net pension expense $ 4.7 2.0 1.2
_________________________________________________________________________________________
Discount rate 8% 7-1/4% 9%
_________________________________________________________________________________________
Compensation increase 5% 5% 5%
_________________________________________________________________________________________
_________________________________________________________________________________________
Return on assets 9% 9% 9%
_________________________________________________________________________________________
The Company has postretirement medical and dental care plans for
all eligible retirees and their dependents with eligibility based
on age and years of service upon retirement. The Company also
maintains a Medicare Part B reimbursement plan and life insurance
coverage for a closed group of retirees of a former subsidiary for
which estimated benefits of approximately $4.7 million were accrued
at December 31, 1992. Effective January 1, 1993, the Company
adopted Statement of Financial Accounting Standards No. 106 (SFAS
No. 106) - "Employers' Accounting for Postretirement Benefits Other
than Pensions," which changed the Company's practice of accounting
for postretirement benefits on a pay-as-you-go (cash) basis by
requiring accrual, during the years that the employee renders the
necessary service, of the expected cost of providing those benefits
to an employee and the employee's beneficiaries and covered
dependents. Upon adoption, the Company recorded a transition
liability of approximately $20.5 million ($13.5 million after
income taxes) as a one-time, non-cash charge against earnings in
the first quarter of 1993.
The postretirement benefit plans are unfunded and the Company
continues to fund claims on a cash basis. The following tables set
forth the amounts recognized in the statements of financial
position and results of operations at December 31:
<CATION>
(Millions of dollars) 1994 1993
_________________________________________________________________________________________
Accumulated postretirement benefit obligation:
Retirees $ (21.3) (20.6)
Employees eligible to retire (2.4) (2.7)
Other employees (4.3) (5.0)
_________________________________________________________________________________________
(28.0) (28.3)
Unrecognized net loss 1.1 2.3
_________________________________________________________________________________________
Accrued postretirement benefit cost $ (26.9) (26.0)
_________________________________________________________________________________________
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Service cost $ 1.3 .8 -
Interest cost 2.1 2.1 -
Pay-as-you-go cost - - .9
_________________________________________________________________________________________
Net postretirement benefit cost $ 3.4 2.9 .9
_________________________________________________________________________________________
Assumptions utilized to measure the accumulated postretirement
obligation at December 31, 1994 and 1993 were: discount rates of
8% and 7.25%, respectively; a health care cost trend rate of 14%
declining over 10 years to 5% and held constant thereafter. A 1%
increase in the assumed trend rates would have resulted in
increases in the accumulated postretirement benefit obligation at
December 31, 1994 and 1993 of $1.7 million and $2.6 million,
respectively; the aggregate of service cost and interest cost for
the years ended December 31, 1994 and 1993 would have increased by
$.5 million and $.4 million, respectively.
14. Capital Stock, Options and Rights
In November 1993, the Company completed a public offering of 4.4
million shares of capital stock at a price of $44.625 per share.
The capital stock was taken from the Company's treasury at an
average cost of $33.125 per share. The excess of net proceeds over
the cost of treasury stock issued was credited to additional paid-
in capital. The net proceeds of the offering, after underwriting
commissions and expenses, were approximately $188.8 million.
Under the 1988 Long-term Stock Incentive Plan, the Company may
grant to officers and key employees stock options, stock
appreciation rights, performance shares, performance units,
restricted stock or restricted stock units for up to 2.8 million
shares of the Company's capital stock. Stock options are
exercisable at the market price on the date of the grant, generally
over a two-year period at the rate of 50% each year commencing on
the first anniversary of the date of grant; all options expire ten
years from the date of grant. In 1994 and 1993, options for
250,100 shares and 257,700 shares were granted, respectively. The
restricted stock and performance shares awarded under the plan
entitle the grantee to the rights of a shareholder, including the
right to receive dividends and to vote such shares, but the shares
are restricted as to sale, transfer or encumbrance. Restricted
stock is released to the grantee over varying periods after a one-
year waiting period has expired. In 1994 and 1993, awards were
granted for 9,000 shares and 34,250 shares of restricted stock,
respectively. In 1994, 12,081 shares were released to grantees;
none were released in 1993. The performance cycle consists of a
three-year period, beginning with the year of grant, at the end of
which certain performance goals must be attained by the Company for
the unrestricted performance shares to be issued to the grantee.
Awards granted in 1994 and 1993 for performance shares amounted to
19,500 shares and 18,900 shares, respectively. Performance shares
issued in 1994 and 1993 amounted to 10,496 shares and 15,257
shares, respectively. Restricted stock and performance share
awards are "compensatory" awards and the Company accrued
compensation expense of $.1 million, $.7 million and $1 million in
1994, 1993 and 1992, respectively.
Under the 1990 Stock Option Plan for Non-Employee Directors, which
expired in May 1994, the Company could grant stock options to non-
employee directors for up to 150,000 shares of the Company's
capital stock. As prescribed by the plan, the options are
exercisable at the market price at the date of grant over a two-
year period at the rate of 50% each year commencing on the first
anniversary of the date of grant; all options expire ten years from
the date of grant. Awards for 22,500 shares and 20,000 shares were
granted in 1994 and 1993, respectively.
At December 31, 1994, 919,372 shares of capital stock were reserved
for future grants under all plans.
Total grants outstanding under the plans and the changes therein
for the periods indicated follows:
Number Option
of shares price range
__________________________________________________________________________________________
Outstanding at December 31, 1992 1,719,353 $27 1/8 - 45 1/2
Granted 330,850 44 3/8 - 45 7/16
Cancelled (6,354) 29 3/4 - 45 7/16
Exercised (453,085) 27 1/8 - 39 11/16
__________________________________________________________________________________________
Outstanding at December 31, 1993 1,590,764 27 1/8 - 45 7/16
Granted 301,100 36 - 41 1/4
Cancelled (25,627) 29 3/4 - 45 1/2
Exercised (226,952) 29 3/4 - 39 11/16
__________________________________________________________________________________________
Outstanding at December 31, 1994 1,639,285 27 1/8 - 45 1/2
__________________________________________________________________________________________
Exercisable at December 31, 1994 1,178,850 27 1/8 - 45 1/2
__________________________________________________________________________________________
Weighted average prices:
Outstanding at December 31, 1994 36 3/16
Exercisable at December 31, 1994 35 1/8
__________________________________________________________________________________________
In 1986, the Company's Board of Directors declared a dividend to
shareholders consisting of one Capital Stock Purchase Right on each
outstanding share of capital stock. A Right will also be issued
with each share of capital stock that becomes outstanding prior to
the time the Rights become exercisable or expire. If a person or
group acquires beneficial ownership of 20% or more, or announces a
tender offer that would result in beneficial ownership of 20% or
more, of the shares of outstanding capital stock, the Rights become
exercisable ten days thereafter and each Right will entitle its
holder to purchase one share of capital stock for $90.
If the Company is acquired in a business combination transaction,
each Right not owned by the 20% holder will entitle its holder to
purchase, for $90, common shares of the acquiring company having a
market value of $180. Alternatively, if a 20% holder were to
acquire the Company by means of a reverse merger in which the
Company and its capital stock survive or were to engage in certain
"self-dealing" transactions, or if a person or group were to
acquire 30% or more of the outstanding capital stock (other than
pursuant to a cash offer for all shares), each Right not owned by
the acquiring person would entitle its holder to purchase, for $90,
capital stock of the Company having a market value of $180. Each
Right can be redeemed by the Company for $.05, subject to the
occurrence of certain events and other restrictions, and expires in
1996. These Rights may cause substantial ownership dilution to a
person or group who attempts to acquire the Company without
approval of the Company's Board of Directors. The Rights should
not interfere with a business combination transaction that has been
approved by the Board of Directors.
15. Contingencies
The Company has been notified by the U.S. Environmental Protection
Agency that it is one of many Potentially Responsible Parties (PRP)
at three National Priorities List sites. Based on its evaluation
of the potential total cleanup costs, its estimate of its potential
exposure, and the viability of the other PRP's, the Company
believes that any costs ultimately required to be borne by it at
these sites will not have a material adverse effect on its results
of operations, cash flow or financial position.
The Company is subject to other legal proceedings, claims and
liabilities which arise in the ordinary course of its business. In
the opinion of Management, the amount of ultimate liability with
respect to these actions will not have a material adverse effect on
results of operations, cash flow or financial position of the
Company.
16. Petroleum Segment Information*
(Millions of dollars) 1994 1993 1992
_________________________________________________________________________________________
Sales to unaffiliated customers:
Domestic $ 678.1 692.9 686.2
North Sea 92.9 40.3 46.4
Other foreign 18.3 60.6 33.2
_________________________________________________________________________________________
789.3 793.8 765.8
Interest and other income 12.2 21.6 21.6
_________________________________________________________________________________________
Total revenues $ 801.5 815.4 787.4
_________________________________________________________________________________________
Earnings (loss) before income taxes:
Operating profit (loss):
Domestic (265.7) 79.2 39.7
North Sea 5.5 (7.7) 13.1
Other foreign (30.7) 16.5 (2.9)
_________________________________________________________________________________________
(290.9) 88.0 49.9
Other income (expense), net (54.7) (63.4) (52.0)
_________________________________________________________________________________________
Earnings (loss) before income taxes $ (345.6) 24.6 (2.1)
_________________________________________________________________________________________
Identifiable industry assets:
Domestic 793.9 1,089.6 705.1
North Sea 518.8 523.2 280.3
Other foreign 92.6 99.5 107.6
_________________________________________________________________________________________
1,405.3 1,712.3 1,093.0
Other assets 72.8 126.4 116.1
_________________________________________________________________________________________
Total assets $1,478.1 1,838.7 1,209.1
_________________________________________________________________________________________
Depletion, depreciation and amortization:
Petroleum 196.7 123.4 101.6
Other 5.5 6.4 4.9
_________________________________________________________________________________________
$ 202.2 129.8 106.5
_________________________________________________________________________________________
Capital expenditures:
Exploration:
Domestic 55.3 31.2 22.7
North Sea 1.6 1.8 3.2
Other foreign 16.5 10.0 12.7
_________________________________________________________________________________________
73.4 43.0 38.6
_________________________________________________________________________________________
Development:
Domestic 75.4 58.0 47.9
North Sea 18.2 37.6 27.9
Other foreign 16.0 3.1 30.5
_________________________________________________________________________________________
109.6 98.7 106.3
_________________________________________________________________________________________
Refining and marketing 31.1 18.4 27.6
_________________________________________________________________________________________
214.1 160.1 172.5
Capitalized interest 22.3 18.7 12.9
Other 3.8 3.5 4.4
_________________________________________________________________________________________
$ 240.2 182.3 189.8
_________________________________________________________________________________________
* Includes nonrecurring charges/credits as follows:
1994 - see Notes 2, 3 and 5.
1993 - see Notes 3, 6, 7, 11 and 12.
1992 - see Note 5.
/TABLE
UNAUDITED SUPPLEMENTAL DATA
_________________________________________________________________
MANAGEMENT'S DISCUSSION AND ANALYSIS
_________________________________________________________________
REVIEW OF OPERATIONS (1994 vs 1993)
The Company reported a $226.9 million net loss in 1994 primarily
as a result of fourth quarter nonrecurring charges totaling $319
million ($210.3 million after tax). The non-recurring charges were
related to a change in the procedure for assessing impairment of
the capitalized costs of the Company's assets which resulted in a
$280 million ($185 million after tax) write-down of oil and gas
properties and the write-down of the Company's refinery assets by
$39 million ($25.3 million after tax). In 1993, the Company
reported net earnings of $9.6 million, which included nonrecurring
and extraordinary items as discussed below.
Before inclusion of the write-down of these assets and certain
nonrecurring gains, the Company's net loss totaled $27.6 million in
1994 reflecting lower gross revenues and higher costs and expenses.
Gross revenues, which fell $14 million from the 1993 level, was
significantly impacted by declining worldwide crude oil prices and
domestic natural gas and refined product prices. Costs and
expenses increased due to higher lease operating, depletion,
depreciation and amortization and exploration expenses. Partially
offsetting the adverse effect of these items were a $10 million
pretax gain ($6.5 million after tax) on the reversal of a
previously established provision for the settlement of the Texaco
litigation and a $6.8 million pretax gain ($4.4 million after tax)
on the sale of oil and gas properties.
Oil and Gas Operations
Revenues from oil and gas operations were up $51 million from 1993.
Liquids revenues were up almost $26 million due to increased crude
oil volumes ($38 million), and natural gas revenues were up $23
million primarily due to higher domestic deliveries ($41 million).
The higher revenues from increased crude oil and natural gas
production exceeded the effect of declining worldwide crude oil
prices ($12 million) and lower domestic natural gas prices ($20
million).
Crude oil volumes were higher in 1994 due to an 8,200 barrel per
day (BPD) increase in North Sea operations and an 800 BPD increase
in domestic operations. North Sea volumes were up primarily due to
the late-1993 T-Block acquisition and new wells onstream at Brae
Field. Domestic volumes were up primarily due to the late-1993
acquisition of NERCO and new domestic wells onstream. These
production increases at domestic and North Sea properties were
partially offset by natural declines at mature producing
properties. Volumes from other foreign operations were down 3,000
BPD primarily due to the sale of certain Canadian properties in
late 1993.
Natural gas deliveries were up 57 million cubic feet per day
(MMCFD) in 1994. An improvement in domestic deliveries, which
accounted for 49 MMCFD of the increase, was due to the acquisition
of NERCO, new wells onstream and the return to production of wells
which were shut-in for repairs and maintenance during the prior
year. North Sea natural gas sales volumes, which were 5 MMCFD
higher due to the completion of the SAGE Pipeline System during
1994, also contributed to the increase. These increases were
partially offset by the effects of natural declines at mature
producing properties, the sales of a limited number of domestic
properties in 1994 and certain Canadian properties in late 1993,
and the voluntary curtailment of some domestic sales volumes in the
second half of 1994 in response to low prices.
Lease operating and facility expenses increased $9 million during
the current year primarily due to additional operating expenses for
properties acquired in late 1993 and higher repair and maintenance
costs on older properties. These costs were partially offset by
lower operating expenses and workover costs on existing properties.
Depletion, depreciation and amortization (DD&A) was $72 million
higher in 1994 than in the prior year due primarily to DD&A on
properties and working interests acquired in late 1993 and new
producing wells onstream in 1994. The increase was partially
offset by the reduction in DD&A for the Canadian properties sold in
1993. Dry holes and exploratory charges were up $21 million in
1994 due to the write-off of unsuccessful wells and higher domestic
seismic costs incurred and lease impairment. Interest and debt
expenses were down $3 million primarily due to increased interest
capitalized on qualifying projects and the inclusion in the prior
year of the aforementioned $6.7 million write-off of debt-issue
costs.
Refining Operations
Refining operations resulted in a pretax operating profit of $2
million in 1994 (before the $39 million write-down of refinery
assets), compared to a $10 million pretax operating loss in the
prior year. The favorable impact of lower crude oil feedstock
costs ($50 million) due to lower prices ($32 million) and volumes
($12 million) and the inclusion in the prior year's costs of the $6
million inventory write-down more than offset the effect of higher
operating expenses ($4 million) and revenue declines ( $36
million). Revenues were down as a result of lower sales volumes
($12 million) and product prices ($24 million).
REVIEW OF OPERATIONS (1993 vs 1992)
Gross revenues in 1993 were up $28 million as an increase in oil
and gas revenues of $46 million and a $24 million pretax gain on
the sale of certain Canadian oil and gas assets more than offset a
$40 million decline in refining revenues and reduced equity in the
earnings of CLAM. CLAM's reduced earnings for 1993 reflect the
adverse effect of reduced gas prices, lower gas deliveries and a
one-time non-cash charge of $6 million to income taxes ($3 million
net to the Company) for the adoption of SFAS No. 109.
Before inclusion of nonrecurring after-tax items netting to a
charge of $1.3 million, an extraordinary loss on early retirement
of debt of $3.3 million and the favorable effect of two accounting
changes amounting to $.2 million, the Company generated earnings of
$14 million in 1993. This represents a decline from the comparable
1992 earnings of $18.9 million, which was also exclusive of
nonrecurring after-tax items totaling $20.1 million and an
extraordinary loss of $5.6 million on the early retirement of debt
in 1992. The nonrecurring items in 1993 consisted of the
aforementioned $23.5 million ($13.2 million after tax) gain on the
sale of certain oil and gas properties, undeveloped acreage and
seismic data located in southern Alberta, Canada reduced by a $6.5
million ($4.2 million after tax) charge for the write-down of
refinery inventories to market value, a $6.7 million ($4.3 million
after tax) charge for the write-off of costs associated with the
interim financing provided by banks for the acquisitions of NERCO
and T-Block, a $3 million income tax charge to recognize the
retroactive rate change enacted in the Budget Reconciliation Act of
1993 and the effect of the aforementioned non-cash charge of $6
million ($3 million net to the Company) to the earnings of CLAM.
The inclusion of the nonrecurring and extraordinary items resulted
in net earnings of $9.6 million in 1993, as compared to the $6.8
million net loss incurred in the prior year.
Oil and Gas Operations
Revenues from oil and gas operations were up $46 million from 1992.
Natural gas revenues, up almost $55 million as a result of higher
domestic gas prices ($29 million) and deliveries ($25 million),
accounted for much of the increase. Liquids revenues, however,
were down $5 million. Although crude oil volumes increased in 1993
($22 million), this revenue gain was more than offset by declining
worldwide crude oil prices ($26 million).
Domestic natural gas deliveries were up almost 40 MMCFD from the
prior year period. The improvement in domestic natural gas
deliveries was due to the acquisition of NERCO, new domestic wells
coming onstream and the return to production of wells previously
shut-in for repairs and maintenance. These increases were
partially offset by the effects of natural declines at mature
producing properties.
Crude oil volumes in 1993 were higher due to a 2,400 BPD increase
in domestic operations, a 300 BPD increase in North Sea operations
and an 800 BPD increase in other foreign operations. The increase
in domestic operations resulted primarily from the acquisition of
NERCO, the purchase of additional working interests in producing
properties, new domestic wells coming onstream, and increased
production from domestic wells that were shut-in for repairs and
maintenance during the prior year. Volumes were up in the North Sea
primarily as a result of the purchase of additional working
interests in producing properties and the production from T-Block
beginning in mid-December 1993. The year-end 1992 acquisition of
a working interest in the KAKAP Field in Indonesia resulted in
higher volumes from other foreign areas. These production
increases were partially offset by natural declines at domestic and
foreign properties.
Lease operating and facility expenses increased $8 million during
1993 primarily due to operating expenses associated with properties
and increased working interests acquired in late 1992 and in 1993
and higher operating and repair and maintenance costs on older
properties. These were partially offset by lower workover charges
and the inclusion in 1992 of a $3 million nonrecurring charge for
the uninsured costs associated with a gas well blowout. Depletion,
depreciation and amortization was $23 million higher in 1993 than
in the prior year due primarily to DD&A on properties and increased
working interests acquired in late 1992 and in 1993. Dry holes and
exploratory charges were up over $7 million in the current year due
to increases in seismic costs incurred, lease impairment and
unsuccessful exploratory wells. General, administrative and other
expenses increased over $6 million from the prior year primarily
due to the initial accrual of current year costs associated with
postretirement benefits other than pensions and increased personnel
costs. Interest and debt expenses increased over $3 million due to
higher interest expense associated with the increased debt level
and the aforementioned write-off of debt-issue costs. These
additional costs were partially offset by interest capitalized on
a greater investment in qualifying projects.
Refining Operations
Refining operations resulted in a loss in 1993. Lower revenues
from a decline in product prices ($49 million), a write-down of
refinery inventories of over $6 million and higher operating
expenses ($4 million) more than offset the favorable impact of
higher sales volumes ($9 million) and lower feedstock prices ($30
million) resulting in a $10 million pretax operating loss. The
refinery had generated a pretax operating profit of $10 million in
the prior year.
LIQUIDITY AND CAPITAL RESOURCES
In 1994, the Company generated approximately $212 million in cash
from operations which, along with advances against cash surrender
value of life insurance policies ($34 million), proceeds from asset
sales ($15 million) and available cash, was utilized for capital
projects ($237 million) and dividends ($33 million). The only
significant long-term debt due in 1994, the $133.5 million balance
of the Term Loan with banks which was due in July 1994, was
refinanced in January 1994 with the proceeds of a revolving credit
facility drawdown.
The Company expects that its 1995 capital and exploration program,
presently estimated at approximately $214 million, will be financed
substantially by internally generated funds, reduced dividend
expenditures and the proceeds from sales of nonstrategic assets.
The Company does not expect to realize any significant losses from
these sales. The Company's expenditures are continually reviewed,
and revised as necessary, based on perceived current and long-term
economic conditions.
In February 1995, the Company announced its plans to sell its
remaining oil and gas assets in Canada. In 1994, these operations
produced 500 barrels of liquids and 3,000 cubic feet of gas per day
and generated revenues of $5.2 million and an operating loss of
$4.7 million.
As explained in Note 15, the Company has been notified by the U.S.
Environmental Protection Agency that it is one of many Potentially
Responsible Parties at three National Priorities List sites. In
the opinion of Management, the ultimate liability with respect to
these matters will not have a material adverse effect on the
results of operations, cash flow or financial position of the
Company.
As explained in Note 9, the Company has only limited involvement
with derivative financial instruments and does not use them for
trading purposes. They are used solely to manage well-defined
interest rate, foreign currency and commodity price risks.
CAPITAL STOCK, DIVIDENDS AND OTHER MARKET DATA
The Company's capital stock is listed and traded on the New York
Stock Exchange, the London Stock Exchange and the Swiss Stock
Exchanges (Basle, Geneva and Zurich). As of February 28, 1995,
there were 7,569 holders of record. The quarterly market prices
for the past two years and the cash dividends paid in each period
are presented in the table on page 72.
In January 1995, the Company announced that its quarterly dividend
of $0.25 per share was being reduced to $0.06 per share with the
savings being redirected to the capital and exploration program.
In November 1993, 4.4 million of the Company's treasury shares were
issued in a public offering. (See Note 14 of "Notes to
Consolidated Financial Statements.") The remaining 4.6 million
shares being held as treasury shares continued to afford the
Company financial flexibility to respond to financing and other
opportunities that might arise.
In 1986, the Company's Board of Directors declared a dividend to
shareholders consisting of one Capital Stock Purchase Right on each
outstanding share of capital stock. These rights may cause
substantial ownership dilution to a person or group who attempts to
acquire the Company without approval of the Company's Board of
Directors. The rights should not interfere with a business
combination transaction that has been approved by the Board of
Directors. (See Note 14 of "Notes to Consolidated Financial
Statements.")
The Company has reserved 2,558,657 shares of its capital stock for
future grants and exercises of stock options. (See Note 14 of
"Notes to Consolidated Financial Statements.")
NOTE:
The accompanying consolidated financial statements and notes
thereto and the unaudited supplemental data are an integral
part of this discussion and analysis and should be read in
conjunction herewith.
_________________________________________________________________
DATA ON OIL AND GAS ACTIVITIES (Unaudited)
_________________________________________________________________
Proved Reserves and Changes Therein
The tables below set forth estimates of the proved reserves
attributable to the working and royalty interests of the Company
(net of royalties payable to other parties) along with a summary of
the changes in the quantities of proved reserves during the periods
indicated. Also set forth is the Company's 50% equity interest in
the proved reserves of CLAM Petroleum Company. The Company
emphasizes that the volumes of reserves shown below are estimates
which, by their nature, are subject to revision. The estimates are
made using all available geological and reservoir data as well as
production performance data. These estimates are reviewed annually
and revised, either upward or downward, as warranted by additional
performance data. There have been no significant changes in the
estimates of proved reserves since December 31, 1994.
Liquids (Millions of barrels)
North Other
Domestic Sea CLAM Foreign Total
_________________________________________________________________________________________
Proved reserves at December 31, 1991 47.0 25.5 .4 11.4 84.3
Revisions of previous estimates 5.3 (.6) - - 4.7
Purchase of reserves in place 2.6 - - 5.8 8.4
Extensions, discoveries and
other additions 3.0 2.8 - .6 6.4
Production (7.9) (2.5) - (2.1) (12.5)
Sales of reserves in place (.6) - - - (.6)
_________________________________________________________________________________________
Proved reserves at December 31, 1992 49.4 25.2 .4 15.7 90.7
Revisions of previous estimates (2.8) (.2) - 2.5 (.5)
Purchase of reserves in place 11.9 17.5 - - 29.4
Extensions, discoveries and
other additions 1.7 - - .8 2.5
Production (8.8) (2.5) - (2.4) (13.7)
Sales of reserves in place (.2) - - (5.1) (5.3)
_________________________________________________________________________________________
Proved reserves at December 31, 1993 51.2 40.0 .4 11.5 103.1
Revisions of previous estimates 2.8 (2.6) (.1) (.1) -
Extensions, discoveries and
other additions 8.6 2.3 - - 10.9
Production (9.1) (5.6) - (1.2) (15.9)
Sales of reserves in place (1.0) - - - (1.0)
_________________________________________________________________________________________
Proved reserves at December 31, 1994 52.5 34.1 .3 10.2 97.1
_________________________________________________________________________________________
Proved-developed reserves at December 31,
_________________________________________________________________________________________
1992 46.8 6.1 .3 10.4 63.6
_________________________________________________________________________________________
1993 47.0 36.9 .3 5.7 89.9
_________________________________________________________________________________________
1994 48.1 32.7 .2 4.4 85.4
_________________________________________________________________________________________
/TABLE
Gas (Billions of cubic feet)
North Other
Domestic Sea CLAM Foreign Total
_________________________________________________________________________________________
Proved reserves at December 31, 1991 520.9 123.4 188.5 10.6 843.4
Revisions of previous estimates 9.7 (4.6) (6.6) (.2) (1.7)
Purchase of reserves in place 3.2 - - - 3.2
Extensions, discoveries and
other additions 14.7 15.8 - .6 31.1
Production (51.3) (.1) (14.8) (1.8) (68.0)
Sales of reserves in place (53.1) - - - (53.1)
_________________________________________________________________________________________
Proved reserves at December 31, 1992 444.1 134.5 167.1 9.2 754.9
Revisions of previous estimates 20.5 (3.2) (.6) 1.0 17.7
Purchase of reserves in place 221.6 11.5 - - 233.1
Extensions, discoveries and
other additions 12.2 - - 2.6 14.8
Production (65.6) (.1) (12.6) (1.9) (80.2)
Sales of reserves in place (1.2) - - (3.2) (4.4)
_________________________________________________________________________________________
Proved reserves at December 31, 1993 631.6 142.7 153.9 7.7 935.9
Revisions of previous estimates 16.6 (4.5) (2.8) (1.7) 7.6
Purchase of reserves in place 3.4 - - - 3.4
Extensions, discoveries and
other additions 116.4 26.0 1.0 5.2 148.6
Production (83.6) (1.8) (14.6) (1.1) (101.1)
Sales of reserves in place (10.7) - - - (10.7)
_________________________________________________________________________________________
Proved reserves at December 31, 1994 673.7 162.4 137.5 10.1 983.7
_________________________________________________________________________________________
Proved-developed reserves at December 31,
1992 270.9 35.3 112.7 9.2 428.1
_________________________________________________________________________________________
1993 405.9 132.9 118.9 7.7 665.4
_________________________________________________________________________________________
1994 493.5 146.4 116.1 10.1 766.1
_________________________________________________________________________________________
The table below sets forth estimates of the domestic sulphur
reserves attributable to the Company's interests as of December 31:
Proved-
(Thousands of long tons) Proved developed
_________________________________________________________________________________________
1992 608.3 242.6
_________________________________________________________________________________________
1993 583.6 226.1
_________________________________________________________________________________________
1994 670.3 670.3
_________________________________________________________________________________________
_________________________________________________________________
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
The following supplemental data on the Company's oil and gas
activities were prepared in accordance with the Financial
Accounting Standards Board's (FASB) Statement of Financial
Accounting Standards No. 69 - "Disclosures About Oil and Gas
Producing Activities." Estimated future net cash flows are
determined by: (1) applying the respective year-end oil and gas
prices to the Company's estimates of future production of proved
reserves; (2) deducting estimates of the future costs of
development and production of proved reserves based on the assumed
continuation of the cost levels and economic conditions existing at
the respective year-end; and (3) deducting estimates of future
income taxes based on the respective year-end and future statutory
tax rates. Present value is determined using the FASB-prescribed
discount rate of 10% per annum.
Although the information presented is based on the Company's best
estimates of the required data, the methods and assumptions used in
preparing the data were those prescribed by the FASB. Although
unrealistic, they were specified in order to achieve uniformity in
assumptions and to provide for the use of reasonably objective
data. It is important to note here that this information is
neither fair market value nor the present value of future cash
flows and it does not reflect changes in oil and gas prices
experienced since the respective year-end. It is primarily a tool
designed by the FASB to allow for a reasonable comparison of oil
and gas reserves and changes therein through the use of a
standardized method. Accordingly, the Company cautions that this
data should not be used for other than its intended purpose.
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1994:
North Other
(Millions of dollars) Domestic Sea Foreign Total
_________________________________________________________________________________________
Future cash inflows $1,898.9 1,011.5 181.4 3,091.8
Future production and development costs (889.8) (254.9) (102.5) (1,247.2)
Future income tax expenses (165.2) (234.2) (18.9) (418.3)
_________________________________________________________________________________________
Future net cash flows 843.9 522.4 60.0 1,426.3
10% annual discount for estimated timing
of cash flows (292.6) (179.1) (26.7) (498.4)
_________________________________________________________________________________________
Standardized measure of discounted future
net cash flows $ 551.3 343.3 33.3 927.9
_________________________________________________________________________________________
CLAM $ - 40.7 - 40.7
_________________________________________________________________________________________
Note: If the post year-end prices utilized by the Company in the write-down of its oil and
gas properties (see Note 2 of "Notes to Consolidated Financial Statements") were
applied, the undiscounted and discounted Standardized Measure would have been
reduced to $1,287 million and $846 million, respectively.
PRINCIPAL SOURCES OF CHANGE DURING 1994:
(Millions of dollars)
_________________________________________________________________________________________
Sales and transfers, net of production costs $(274.2)
Net change in prices and production costs (81.2)
Extensions, discoveries and improved recovery,
less related costs 164.6
Net change in future development costs (27.4)
Previously estimated development costs
incurred during the year 107.6
Revisions of previous reserve estimates 5.9
Purchase of reserves in place 2.0
Sales of reserves in place (12.6)
Accretion of discount 113.8
Net change in income taxes 27.2
Other (21.2)
_________________________________________________________________________________________
Net change $ 4.5
_________________________________________________________________________________________
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1993:
North Other
(Millions of dollars) Domestic Sea Foreign Total
_________________________________________________________________________________________
Future cash inflows $2,153.6 933.2 160.1 3,246.9
Future production and development costs (996.1) (287.3) (110.2) (1,393.6)
Future income tax expenses (228.1) (149.8) (9.6) (387.5)
_________________________________________________________________________________________
Future net cash flows 929.4 496.1 40.3 1,465.8
10% annual discount for estimated timing
of cash flows (347.6) (180.9) (13.9) (542.4)
_________________________________________________________________________________________
Standardized measure of discounted future
net cash flows $ 581.8 315.2 26.4 923.4
_________________________________________________________________________________________
CLAM $ - 51.8 - 51.8
_________________________________________________________________________________________
PRINCIPAL SOURCES OF CHANGE DURING 1993:
(Millions of dollars)
_________________________________________________________________________________________
Sales and transfers, net of production costs $(225.9)
Net change in prices and production costs (209.6)
Extensions, discoveries and improved recovery,
less related costs 25.6
Net change in future development costs (14.6)
Previously estimated development costs
incurred during the year 56.6
Revisions of previous reserve estimates 10.1
Purchase of reserves in place 414.7
Sales of reserves in place (24.1)
Accretion of discount 101.3
Net change in income taxes 100.6
Other (12.7)
_________________________________________________________________________________________
Net change $ 222.0
_________________________________________________________________________________________
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1992:
North Other
(Millions of dollars) Domestic Sea Foreign Total
_________________________________________________________________________________________
Future cash inflows $1,794.9 779.0 276.6 2,850.5
Future production and development costs (715.7) (261.0) (145.0) (1,121.7)
Future income tax expenses (292.4) (241.4) (38.2) (572.0)
_________________________________________________________________________________________
Future net cash flows 786.8 276.6 93.4 1,156.8
10% annual discount for estimated timing
of cash flows (313.9) (113.6) (27.9) (455.4)
_________________________________________________________________________________________
Standardized measure of discounted future
net cash flows $ 472.9 163.0 65.5 701.4
_________________________________________________________________________________________
CLAM $ - 65.1 - 65.1
_________________________________________________________________________________________
PRINCIPAL SOURCES OF CHANGE DURING 1992:
(Millions of dollars)
_________________________________________________________________________________________
Sales and transfers, net of production costs $(203.3)
Net change in prices and production costs (9.2)
Extensions, discoveries and improved recovery,
less related costs 57.9
Net change in future development costs 12.3
Previously estimated development costs
incurred during the year 70.5
Revisions of previous reserve estimates 47.6
Purchase of reserves in place 61.7
Sales of reserves in place (52.2)
Accretion of discount 69.1
Net change in income taxes 3.3
Other (47.1)
_________________________________________________________________________________________
Net change $ 10.6
_________________________________________________________________________________________
_________________________________________________________________________________________
RESULTS OF OPERATIONS FOR OIL AND GAS ACTIVITIES
Years ended December 31:
North Other
19941 (Millions of dollars) Domestic Sea Foreign Total
_________________________________________________________________________________________
Revenues $ 316.82 92.9 18.3 428.0
Production costs (90.5) (36.9) (9.4) (136.8)
Exploration expenses (44.8) (2.6) (22.3) (69.7)
DD&A (142.6) (41.9) (8.9) (193.4)
Write-down of oil and gas properties (265.6) (6.0) (8.4) (280.0)
_________________________________________________________________________________________
(226.7) 5.5 (30.7) (251.9)
Income tax (expense) benefit 79.0 (9.0) 13.6 83.6
_________________________________________________________________________________________
Earnings (loss)3 $(147.7) (3.5) (17.1) (168.3)
_________________________________________________________________________________________
CLAM4 $ - 3.9 - 3.9
_________________________________________________________________________________________
19931 (Millions of dollars)
_________________________________________________________________________________________
Revenues 292.72 40.3 60.6 393.6
Production costs (83.8) (24.9) (17.8) (126.5)
Exploration expenses (31.4) (3.8) (13.6) (48.8)
DD&A (86.2) (19.3) (12.7) (118.2)
_________________________________________________________________________________________
91.3 (7.7) 16.5 100.1
Income tax (expense) benefit (32.0) 1.5 (6.8) (37.3)
_________________________________________________________________________________________
Earnings (loss)3 $ 59.3 (6.2) 9.7 62.8
_________________________________________________________________________________________
CLAM4 $ - 2.3 - 2.3
_________________________________________________________________________________________
19921(Millions of dollars)
_________________________________________________________________________________________
Revenues 244.32 46.4 33.2 323.9
Production costs (79.5) (20.0) (18.2) (117.7)
Exploration expenses (30.5) (4.1) (6.9) (41.5)
DD&A and restructuring charge (104.1) (9.2) (11.0) (124.3)
_________________________________________________________________________________________
30.2 13.1 (2.9) 40.4
Income tax (expense) benefit (9.6) (8.4) .9 (17.1)
_________________________________________________________________________________________
Earnings (loss)3 $ 20.6 4.7 (2.0) 23.3
_________________________________________________________________________________________
CLAM4 $ - 6.4 - 6.4
_________________________________________________________________________________________
1 Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
Statements" as follows:
1994 - see Notes 2 and 3.
1993 - see Note 3.
1992 - see Note 5.
2 Includes intercompany transfers to the Company's refinery of $24.8, $22.4 and $20.7 in
1994, 1993 and 1992, respectively.
3 Excludes other income, general and administrative expenses, and interest and debt
expenses.
4 Represents the Company's equity in CLAM's net earnings after U.S. income taxes. See
Note 7 of "Notes to Consolidated Financial Statements."
_________________________________________________________________________________________
COSTS INCURRED IN OIL AND GAS ACTIVITIES
Years ended December 31:
North Other
1994 (Millions of dollars) Domestic Sea Foreign Total
_________________________________________________________________________________________
Property acquisition:
Proved $ 2.0 - - 2.0
Unproved 2.3 - 1.1 3.4
Exploration 69.5 2.5 20.0 92.0
Development 73.4 18.3 15.9 107.6
_________________________________________________________________________________________
147.2 20.8 37.0 205.0
Capitalized interest 7.3 14.7 .3 22.3
_________________________________________________________________________________________
$ 154.5 35.5 37.3 227.3
_________________________________________________________________________________________
CLAM $ - 10.5 - 10.5
_________________________________________________________________________________________
1993 (Millions of dollars)
_________________________________________________________________________________________
Property acquisition:
Proved 364.2 159.4 - 523.6
Unproved 4.5 40.8 1.2 46.5
Exploration 39.1 2.1 17.7 58.9
Development 52.2 24.2 3.1 79.5
_________________________________________________________________________________________
460.0 226.5 22.0 708.5
Capitalized interest 3.9 14.8 - 18.7
_________________________________________________________________________________________
$ 463.9 241.3 22.0 727.2
_________________________________________________________________________________________
CLAM $ - 5.2 - 5.2
_________________________________________________________________________________________
1992 (Millions of dollars)
_________________________________________________________________________________________
Property acquisition:
Proved 8.3 - 27.5 35.8
Unproved 2.5 - 8.1 10.6
Exploration 29.8 3.5 7.8 41.1
Development 39.5 27.9 3.1 70.5
_________________________________________________________________________________________
80.1 31.4 46.5 158.0
Capitalized interest 4.0 8.9 - 12.9
_________________________________________________________________________________________
$ 84.1 40.3 46.5 170.9
_________________________________________________________________________________________
CLAM $ - 10.7 - 10.7
_________________________________________________________________________________________
_________________________________________________________________________________________
OIL AND GAS OPERATING DATA1
Years ended December 31:
1994 19932 1992 1991 1990
_________________________________________________________________________________________
CRUDE AND CONDENSATE3
Production (barrels per day):
Domestic:
Working interest 18,833 17,586 15,308 16,439 17,085
Royalty interest 3,678 4,161 4,070 4,070 4,041
_________________________________________________________________________________________
22,511 21,747 19,378 20,509 21,126
North Sea (working interest) 14,769 6,529 6,258 8,352 10,283
Other foreign (working interest) 3,496 6,509 5,674 5,896 6,652
_________________________________________________________________________________________
40,776 34,785 31,310 34,757 38,061
_________________________________________________________________________________________
Average price received (per barrel):
Domestic $ 16.26 17.33 19.85 22.13 21.38
North Sea 16.01 16.20 19.11 19.96 23.13
Other foreign 12.63 14.40 14.98 14.53 18.89
Consolidated 15.86 16.57 18.82 20.32 21.42
_________________________________________________________________________________________
NATURAL GAS
Production (thousands of cubic feet
per day):
Domestic:
Working interest 203,700 155,917 119,050 124,592 126,610
Royalty interest 24,957 23,861 21,146 25,666 24,771
_________________________________________________________________________________________
228,657 179,778 140,196 150,258 151,381
North Sea (working interest) 5,302 156 236 283 349
Other foreign (working interest) 3,018 5,316 4,871 4,388 4,918
CLAM Petroleum Company 40,003 34,608 40,485 48,772 46,330
_________________________________________________________________________________________
276,980 219,858 185,788 203,701 202,978
_________________________________________________________________________________________
Average price received (per MCF):
Domestic $ 1.95 2.19 1.75 1.53 1.74
North Sea 2.20 1.51 1.92 1.91 2.48
Other foreign 1.63 1.27 0.84 1.03 1.13
CLAM Petroleum Company 2.27 2.35 2.73 3.08 2.76
Consolidated 2.00 2.19 1.94 1.89 1.96
_________________________________________________________________________________________
PLANT PRODUCTS
Production (barrels per day):
Domestic (working interest) 2,475 2,377 2,294 2,145 2,197
North Sea (working interest) 552 352 461 510 612
Other foreign (working interest) 6 29 39 33 29
_________________________________________________________________________________________
3,033 2,758 2,794 2,688 2,838
_________________________________________________________________________________________
Average price received (per barrel):
Domestic $ 10.66 11.26 13.07 14.89 14.31
North Sea 11.28 12.62 14.47 16.93 15.36
Other foreign 7.84 11.97 12.68 13.12 13.70
Consolidated 10.28 11.44 13.29 15.26 14.53
_________________________________________________________________________________________
1 Includes the Company's 50% equity interest in its unconsolidated affiliate,
CLAM Petroleum Company.
2 Includes NERCO Oil & Gas, Inc. since October 1, 1993.
3 Before the elimination of intercompany transfers.
/TABLE
_________________________________________________________________________________________
REFINING OPERATING DATA
Years ended December 31:
(Millions of dollars) 1994 1993 1992 1991 1990
_________________________________________________________________________________________
Refining operating profit (loss):
Revenues:
Refined products* $ 386.1 422.6 462.6 451.5 453.8
Other 2.1 1.9 .3 .2 .7
_________________________________________________________________________________________
388.2 424.5 462.9 451.7 454.5
_________________________________________________________________________________________
Costs and expenses:
Cost of sales* 340.1 390.6 413.6 401.4 396.9
Operating expenses 39.2 35.2 31.4 32.4 33.1
Depreciation 3.3 5.2 5.0 4.7 4.5
Taxes, other than income 3.5 3.5 3.3 2.7 3.4
Write-down of refinery assets 39.0 - - - -
_________________________________________________________________________________________
425.1 434.5 453.3 441.2 437.9
_________________________________________________________________________________________
(36.9) (10.0) 9.6 10.5 16.6
_________________________________________________________________________________________
*Before the elimination of
intercompany transfers to
the Company's refinery $ 24.8 22.4 20.7 18.7 22.3
_________________________________________________________________________________________
Sales (barrels per day):
No. 2 fuel oil 11,572 11,471 12,471 11,079 13,162
Unleaded gasoline 22,571 22,747 23,640 21,675 21,618
Jet fuel 7,166 6,488 5,415 5,102 5,595
Naphtha 4,090 5,477 4,922 4,045 6,260
Other 7,505 8,347 6,880 6,987 8,272
_________________________________________________________________________________________
52,904 54,530 53,328 48,888 54,907
_________________________________________________________________________________________
Average price received (per
barrel) $ 20.00 21.24 23.70 25.30 22.65
_________________________________________________________________________________________
_________________________________________________________________________________________
OIL AND GAS PROPERTIES
December 31, 1994
Productive acreage Undeveloped acreage
(Thousands of acres) Gross Net Gross Net
_________________________________________________________________________________________
LEASEHOLDS AND OPTIONS
Domestic:
Offshore Gulf of Mexico 329.7 160.0 381.5 247.8
Louisiana 118.8 76.4 38.6 17.2
Alabama/Florida 9.2 8.0 .6 .6
Colorado/Utah/New Mexico .8 .1 146.5 92.8
Wyoming 43.9 12.5 226.6 99.1
Other 47.9 5.8 71.4 9.7
_________________________________________________________________________________________
550.3 262.8 865.2 467.2
_________________________________________________________________________________________
North Sea:
Netherlands 2.7 1.0 103.3 36.0
United Kingdom 19.1 1.2 147.2 12.0
_________________________________________________________________________________________
21.8 2.2 250.5 48.0
_________________________________________________________________________________________
Other foreign:
Algeria - - 1,552.9 1,009.4
Australia - - 1,389.0 365.8
Canada 36.2 19.5 190.0 111.2
Colombia 11.7 1.6 216.1 119.4
France - - 113.4 56.7
Indonesia 5.9 .9 489.7 66.2
Papua New Guinea - - 168.4 67.4
Tunisia - - 1,021.0 510.5
Yemen - - 1,167.9 198.5
_________________________________________________________________________________________
53.8 22.0 6,308.4 2,505.1
_________________________________________________________________________________________
FEE LANDS 98.0 98.0 496.0 496.0
_________________________________________________________________________________________
CLAM PETROLEUM COMPANY (50%)
Netherlands-North Sea 39.7 5.6 771.7 176.6
_________________________________________________________________________________________
763.6 390.6 8,691.8 3,692.9
_________________________________________________________________________________________
_______________________________________________________________________________________
WELLS DRILLED
Years ended December 31:
1994 1993 1992 1991 1990
_______________________________________________________________________________________
GROSS WELLS DRILLED (BY LOCATION)
Working interest
Domestic:
Offshore Gulf of Mexico 20 23 5 18 13
Louisiana 14 10 17 30 28
Oklahoma - - - 25 25
Texas - - - 3 -
Wyoming 4 6 2 9 7
Other - - 1 - 1
_______________________________________________________________________________________
38 39 25 85 74
_______________________________________________________________________________________
North Sea:
Netherlands 3 4 5 10 14
United Kingdom 6 5 8 4 8
_______________________________________________________________________________________
9 9 13 14 22
_______________________________________________________________________________________
Other foreign:
Canada 14 38 33 44 44
Colombia 2 - 3 2 4
Other 3 2 1 2 2
_______________________________________________________________________________________
19 40 37 48 50
_______________________________________________________________________________________
Total working interest 66 88 75 147 146
Royalty interest 19 35 26 28 31
_______________________________________________________________________________________
Total wells 85 123 101 175 177
_______________________________________________________________________________________
Gross (Net) Wells Drilled (by type)
Exploratory:
Oil 15 (1.8) 34 (15.2) 26 (13.1) 33 (15.1) 28 (14.4)
Gas 26 (10.3) 18 (3.9) 10 (2.5) 34 (12.4) 40 (15.1)
Dry 22 (9.4) 31 (11.4) 28 (12.4) 74 (29.5) 77 (28.1)
_______________________________________________________________________________________
63 (21.5) 83 (30.5) 64 (28.0) 141 (57.0) 145 (57.6)
_______________________________________________________________________________________
Development:
Oil 7 (1.0) 17 (2.1) 22 (2.6) 23 (2.4) 14 (2.5)
Gas 14 (3.3) 21 (3.4) 6 (1.4) 9 (1.5) 17 (1.7)
Dry 1 (.1) 2 (.3) 9 (.7) 2 (.6) 1 (-)
_______________________________________________________________________________________
22 (4.4) 40 (5.8) 37 (4.7) 34 (4.5) 32 (4.2)
_______________________________________________________________________________________
Total wells 85 (25.9) 123 (36.3) 101 (32.7) 175 (61.5) 177 (61.8)
_______________________________________________________________________________________
_________________________________________________________________________________________
SELECTED FINANCIAL DATA
Years ended December 31:
(Millions of dollars, except per share data)
1994* 1993* 1992* 1991 1990
_________________________________________________________________________________________
Revenues $ 801.5 815.4 787.4 825.3 874.7
Operating profit (loss) $ (290.9) 88.0 49.9 75.2 142.1
Net earnings (loss) $ (226.9) 9.6 (6.8) 20.9 54.9
Primary and fully diluted
earnings (loss) per share $ (6.80) 0.33 (0.24) 0.74 1.94
Average shares (millions) 33.4 29.5 28.4 28.3 28.3
_________________________________________________________________________________________
Cash flows from operations $ 212.1 178.9 178.7 209.2 251.9
Working capital (deficit):
End of year $ (6.4) 15.6 (20.2) 24.2 27.2
Current ratio .97 1.09 .88 1.15 1.17
_________________________________________________________________________________________
Total assets $ 1,478.1 1,838.7 1,209.1 1,252.8 1,226.0
Long-term debt $ 739.5 734.5 343.0 347.3 346.1
Stockholders' equity $ 352.4 599.8 416.6 446.5 448.7
Cash dividends per share $ 1.00 1.00 1.00 1.00 1.00
_________________________________________________________________________________________
*
Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
Statements" as follows:
1994 - see Notes 2, 3 and 5.
1993 - see Notes 3, 6, 7, 11 and 12.
1992 - see Note 5.
_________________________________________________________________________________________
MARKET PRICE AND DIVIDEND DATA
Quarter ended
March 31 June 30 Sept. 30 Dec. 31
_________________________________________________________________________________________
1994:
Capital stock price:
High $43 3/8 45 45 3/8 47 1/8
Low 35 1/8 35 7/8 40 7/8 36 3/8
Cash dividends per share 0.25 0.25 0.25 0.25
_________________________________________________________________________________________
1993:
Capital stock price:
High 47 47 7/8 49 47 1/2
Low 31 40 1/2 40 7/8 37 7/8
Cash dividends per share 0.25 0.25 0.25 0.25
_________________________________________________________________________________________
_________________________________________________________________________________________
QUARTERLY DATA*
Quarter ended
(Millions, except per share data) March 31 June 30 Sept. 30 Dec. 31
_________________________________________________________________________________________
1994:
Revenues $206.7 190.7 197.9 206.2
Costs and expenses 197.8 188.5 216.5 544.3
_________________________________________________________________________________________
Earnings (loss) before income taxes 8.9 2.2 (18.6) (338.1)
Income tax expense (benefit) 2.7 1.6 (7.3) (115.7)
_________________________________________________________________________________________
Net earnings (loss) $ 6.2 .6 (11.3) (222.4)
_________________________________________________________________________________________
Earnings (loss) per share $ 0.19 0.02 (0.34) (6.64)
_________________________________________________________________________________________
Average shares 33.3 33.4 33.4 33.4
_________________________________________________________________________________________
1993:
Revenues 186.9 194.7 193.5 240.3
Costs and expenses 181.9 184.7 190.9 233.3
_________________________________________________________________________________________
Earnings before income taxes 5.0 10.0 2.6 7.0
Income tax expense 2.3 4.4 4.4 .8
_________________________________________________________________________________________
Earnings (loss) before extraordinary
item and accounting changes 2.7 5.6 (1.8) 6.2
Loss on early retirement of debt - - - (3.3)
Changes in accounting principles .2 - - -
_________________________________________________________________________________________
Net earnings (loss) $ 2.9 5.6 (1.8) 2.9
_________________________________________________________________________________________
Earnings (loss) per share before
extraordinary item and
accounting changes 0.09 0.20 (0.06) 0.19
Loss on early retirement of debt - - - (0.10)
Changes in accounting principles 0.01 - - -
_________________________________________________________________________________________
Earnings (loss) per share $ 0.10 0.20 (0.06) 0.09
_________________________________________________________________________________________
Average shares 28.5 28.8 28.9 31.7
_________________________________________________________________________________________
*
Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
Statements" as follows:
1994 - see Notes 2, 3 and 5.
1993 - see Notes 3, 6, 7, 11 and 12.
Independent Auditors' Report
The Partners
MaraLou Netherlands Partnership:
We have audited the accompanying consolidated balance sheets of MaraLou
Netherlands Partnership and subsidiary as of December 31, 1994 and 1993, and
the related consolidated statements of income, partners' capital, and cash
flows for each of the years in the three-year period ended December 31,
1994. These consolidated financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on
these consolidated 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of MaraLou
Netherlands Partnership and subsidiary as of December 31, 1994 and 1993, and
the results of their operations and their cash flows for each of the years
in the three-year period ended December 31, 1994 in conformity with
generally accepted accounting principles.
As discussed in note 4 to the consolidated financial statements, the
Partnership adopted the provisions of the Financial Accounting Standards
Board's Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes" in 1993.
/s/ KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
Houston, Texas
February 8, 1995
MARALOU NETHERLANDS PARTNERSHIP
Consolidated Balance Sheets
December 31, 1994 and 1993
(Expressed in U.S. Dollars)
ASSETS 1994 1993
Current assets:
Cash and cash equivalents $ 4,120,901 $ 11,476,689
Accounts receivable 15,596,130 12,538,332
Accounts receivable - net profits 385,371 327,160
Income tax receivable 3,708,460 3,553,873
Materials and supplies 197,812 6,910
Other current assets 6,606 51,913
Total current assets 24,015,280 27,954,877
Long-term receivable 5,774,218 5,619,856
Property, plant and equipment, at cost, based on
the successful efforts method of accounting for
oil and gas properties 370,624,832 349,664,531
Less accumulated depletion, amortization
and depreciation 201,248,670 184,677,406
Net property, plant and equipment 169,376,162 164,987,125
Deferred charges 182,991 249,523
$ 199,348,651 $ 198,811,381
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable - affiliated companies $ 63,109 $ 63,960
Accrued liabilities 11,188,175 8,912,609
Amounts due to operator of joint venture 1,315,712 3,667,149
Government royalties payable 1,387,035 1,408,245
Income taxes payable 1,893,523 16,170,883
Total current liabilities 15,847,554 30,222,846
Long-term debt 96,000,000 87,800,000
Deferred income taxes 28,725,590 18,772,886
Deferred liability - platform abandonment 21,011,173 20,432,039
Minority interest 2,263,549 2,229,013
Partners' capital:
Marathon Petroleum Netherlands, Ltd. 10,748,498 12,675,404
LL&E (Netherlands), Inc. 10,748,498 12,675,404
Foreign currency translation adjustment 14,003,789 14,003,789
Total partners' capital 35,500,785 39,354,597
$ 199,348,651 $ 198,811,381
See accompanying notes to consolidated financial statements.
/TABLE
MARALOU NETHERLANDS PARTNERSHIP
Consolidated Statements of Income
Years Ended December 31, 1994, 1993 and 1992
(Expressed in U.S. Dollars)
1994 1993 1992
Revenues:
Sales $ 68,663,916 $ 61,152,082 $ 82,902,883
Interest income 1,259,380 4,465,502 2,722,500
Total revenues 69,923,296 65,617,584 85,625,383
Costs and expenses:
Costs and operating expenses 11,079,073 12,349,387 17,514,115
Exploration expenses, including dry
hole costs 4,344,427 3,336,263 3,981,650
Depletion, amortization and
depreciation 16,571,265 14,100,833 15,424,731
General and administrative expenses 5,691,285 4,950,135 5,522,838
Royalty expense 996,651 960,585 2,419,101
Net profits interest 96,232 336,356 1,202,888
Interest expense 5,467,221 7,222,385 7,983,685
Foreign exchange loss/(gain) 543,705 (763,957) (53,951)
Reimbursement of exploration costs,
including interest - - 263,056
Total costs and expenses 44,789,859 42,491,987 54,258,113
Income before income taxes 25,133,437 23,125,597 31,367,270
Provision for income taxes 16,940,713 12,192,472 17,524,381
Income after income taxes 8,192,724 10,933,125 13,842,889
Minority interest 1,126,536 797,688 1,665,693
Income before cumulative effect of
change in accounting principle 7,066,188 10,135,437 12,177,196
Cumulative effect of change in
accounting principle for income
taxes - 6,003,589 -
Net income $ 7,066,188 $ 4,131,848 $ 12,177,196
See accompanying notes to consolidated financial statements.
MARALOU NETHERLANDS PARTNERSHIP
Consolidated Statements of Partners' Capital
Years Ended December 31, 1994, 1993 and 1992
(Expressed in U.S. Dollars)
Marathon
Petroleum L.L.&E.
Netherlands, Inc. (Netherlands), Inc. Total
Capital, January 1, 1994 $12,675,404 $12,675,404 $25,350,808
Net income 3,533,094 3,533,094 7,066,188
Distribution to Partners (5,460,000) (5,460,000) (10,920,000)
Capital before adjustments $10,748,498 $10,748,498 21,496,996
Foreign currency translation
adjustment 14,003,789
Capital, December 31, 1994 $35,500,785
Marathon
Petroleum L.L.&E.
Netherlands, Inc. (Netherlands), Inc. Total
Capital, January 1, 1993 $19,709,480 $19,709,480 $39,418,960
Net income 2,065,924 2,065,924 4,131,848
Distribution to Partners (9,100,000) (9,100,000) (18,200,000)
Capital before adjustments $12,675,404 $12,675,404 $25,350,808
Foreign currency translation
adjustment 14,003,789
Capital, December 31, 1993 $39,354,597
(Continued)
MARALOU NETHERLANDS PARTNERSHIP
Consolidated Statements of Partners' Capital (Continued)
Years Ended December 31, 1994, 1993 and 1992
(Expressed in U.S. Dollars)
Marathon
Petroleum L.L.&E.
Netherlands, Inc. (Netherlands), Inc. Total
Capital, January 1, 1992 $20,470,882 $20,470,882 $ 40,941,764
Net income 6,088,598 6,088,598 12,177,196
Distribution to Partners (6,850,000) (6,850,000) (13,700,000)
Capital before adjustments $19,709,480 $19,709,480 39,418,960
Foreign currency translation
adjustment 14,003,789
Capital, December 31, 1992 $ 53,422,749
See accompanying notes to consolidated financial statements.
/TABLE
MARALOU NETHERLANDS PARTNERSHIP
Consolidated Statements of Cash Flows
Years Ended December 31, 1994, 1993 and 1992
(Expressed in U.S. Dollars)
1994 1993 1992
Cash flows from operating activities:
Net income accruing to MaraLou partners $ 7,066,188 $ 4,131,848 $ 12,177,196
Net (loss)/income accruing to minority
shareholders, net of cash distributions 34,536 (1,022,312) 295,694
Adjustments to reconcile net income to
net cash provided by operating activities:
Depletion, amortization, depreciation
and abandonment 16,571,265 14,100,833 16,280,290
Dry hole costs 3,860,175 1,892,456 2,523,479
Deferred income taxes 9,021,323 (7,951,542) 2,511,807
Exchange loss (gain) 374,213 (175,868) (127,738)
Interest on EBN repayment 281,812 665,428 1,076,991
Cumulative effect of change in accounting
principle - 6,003,589 -
Decrease (increase) in accounts
receivable (2,041,325) 2,175,071 943,544
Increase in accounts receivable - net
profits (19,222) (326,001) -
Decrease (increase) in materials and
supplies (190,902) (65) 69
Decrease (increase) in other current
assets 206,155 (161,390) (380,539)
Decrease (increase) in deferred charges 64,096 18,201 (240,457)
(Decrease) increase in accounts
payable-affiliates (3,255) (6,535) 5,077
(Decrease) increase in accounts
payable-net profits - (228,091) 20,517
Increase (decrease) in accrued
liabilities 1,483,332 677,612 (123,115)
Increase (decrease) in amounts due to
operator of joint venture (2,558,160) 4,676,131 (2,462,784)
(Decrease) increase in government
royalties payable (131,600) (865,267) (869,050)
(Decrease) increase in income taxes
payable (15,179,834) 8,415,273 (3,489,638)
Net cash provided by operating
activities $ 18,838,797 $ 32,019,371 $ 28,141,343
Cash flows from investing activities:
Capital expenditures $ (24,241,343)$ (9,973,617) $(20,034,768)
Net cash used in investing activities (24,241,343) (9,973,617) (20,034,768)
(Continued)
MARALOU NETHERLANDS PARTNERSHIP
Consolidated Statements of Cash Flows (Continued)
Years Ended December 31, 1994, 1993 and 1992
(Expressed in U.S. Dollars)
1994 1993 1992
Cash flows from financing activities:
Borrowing under revolving credit
agreement $ 8,200,000 $ - $ -
Repayments under revolving credit
agreement - (10,000,000) (6,000,000)
Reduction of note receivable by minority
shareholders in CLAM - - 5,629,000
Cash distribution to partners (10,920,000) (18,200,000) (13,700,000)
Net cash used in financing activities (2,720,000) (28,200,000) (14,071,000)
Effect of exchange rate on cash 766,758 (854,829) 1,010,031
Net decrease in cash and cash equivalents (7,355,788) (7,009,075) (4,954,394)
Cash and cash equivalents at beginning of
year $ 11,476,689 $ 18,485,764 $ 23,440,158
Cash and cash equivalents at end of year $ 4,120,901 $ 11,476,689 $ 18,485,764
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest $ 4,487,259 $ 5,543,844 $ 5,224,193
Foreign taxes 23,621,088 13,746,175 17,125,660
Federal taxes (518,116) (1,155,157) 2,345,247
Supplemental schedule of noncash investing and financing activities:
Long-term receivable for EBN
reimbursement $ 154,362 $ (321,870) $ 1,327,240
Accrued liability established for
repayment to EBN (732,141) (191,527) (2,334,052)
See accompanying notes to consolidated financial statements.
MARALOU NETHERLANDS PARTNERSHIP
Notes to Consolidated Financial Statements
December 31, 1994, 1993 and 1992
1. Organization and summary of significant accounting policies
Organization and ownership:
MaraLou Netherlands Partnership (MaraLou), a Texas general
partnership, was formed on March 27, 1985 by LL&E
(Netherlands), Inc. (LL&E Netherlands) and Marathon Petroleum
Netherlands, Ltd. (Marathon Netherlands) for the purpose of
owning their interests in CLAM Petroleum Company (CLAM) and
for the purpose of purchasing the outstanding shares of CLAM
held by Netherlands-Cities Services, Inc. On March 27, 1985
both partners agreed to contribute their respective ten
thousand shares of CLAM to MaraLou. These shares were
transferred to MaraLou on June 21, 1985. The remaining shares
held by Netherlands-Cities Services, Inc. were acquired by
MaraLou for $85,381,881 on March 29, 1985. The acquisition
has been accounted for using the purchase method of accounting
effective January 1, 1985.
On December 6, 1991 an agreement was concluded whereby LL&E
Netherlands Petroleum Company, an affiliated company to LL&E
Netherlands - both of which are wholly owned subsidiaries of
The Louisiana Land and Exploration Company, contributed
Netherlands North Sea license interests and other assets
valued at $11,629,000 for five hundred newly issued shares of
CLAM stock. For financial reporting purposes, the
contribution made by LL&E Netherlands Petroleum Company in
excess of its calculated minority interest is reflected in
Partners' capital as an addition to the LL&E Netherlands
capital balance. MaraLou made a cash contribution of
$11,629,000 for an additional five hundred newly issued shares
of CLAM stock. The contributed cash is to be used to develop
the North Sea license interest contributed by LL&E Netherlands
Petroleum Company. MaraLou subsequently sold all of its newly
issued shares of CLAM stock to Marathon Netherlands, a partner
in MaraLou, which purchased the shares with a note valued at
$11,629,000, on which $6,000,000 was paid in 1991 and
$6,000,000, inclusive of interest, was paid in 1992. These
newly issued shares of CLAM stock have been pledged as
security for MaraLou and CLAM's revolving credit agreement
(see Note 6).
CLAM Petroleum Company, a Delaware Corporation, was formed in
October 1975 by LL&E Netherlands, Marathon Netherlands and
Netherlands-Cities Service, Inc. (stockholders) for the
purpose of owning their interest in certain licenses and
agreements covering hydrocarbon operations in The Netherlands
and for the purpose of entering into agreements with lending
institutions to finance such interest. Effective May 24, 1976
the stockholders assigned their interests and obligations
under the licenses and related agreements to CLAM. CLAM has
no operations outside the oil and gas industry or in areas
other than The Netherlands North Sea.
The financial statements reflect the consolidation of CLAM
Petroleum Company (the Company) with MaraLou for the period
from January 1, 1985. The financial statements also reflect
the interests and earnings of the minority shareholders, LL&E
Netherlands Petroleum Company and Marathon Netherlands.
Currently, MaraLou has no interests other than in the
operation of CLAM.
Cash equivalents:
Cash equivalents of $-0-, $11,133,745 and $18,721,023 at
December 31, 1994, 1993 and 1992, respectively, consist of
Eurodollar and Euroguilder investments. For purposes of the
statements of cash flows, MaraLou considers all highly liquid
debt instruments with original maturities of three months or
less to be cash equivalents.
Joint venture agreements:
CLAM, together with unrelated parties, has interests in
certain prospecting and production licenses and related
operating agreements which provide for the joint conduct of
seismic, geological, exploration and development activities on
the continental shelf of The Netherlands. The accompanying
financial statements include CLAM's share of operations as
reported to it by the operator of the joint venture. The
amounts reported by the operator of the joint venture are
subject to an annual audit by the non-operators. The audit
for the year 1993 has been conducted with the non-operators
awaiting the operator's initial response to the audit report.
Petroleum exploration and development costs:
CLAM follows the successful efforts method of accounting for
oil and gas properties. Exploration expenses, including
geological and geophysical costs, prospecting costs, carrying
costs and exploratory dry hole costs are charged against
income as incurred. The acquisition costs of unproved
properties are capitalized with appropriate provision for
impairment based upon periodic assessments of such properties.
All development costs, including development dry hole costs,
are capitalized. Capitalized costs are adjusted annually for
cash adjustments relating to changes in CLAM's share in gas
reserve estimates (see Note 7).
Depletion, amortization and depreciation:
Depletion is provided under the unit-of-production method
based upon estimates of proved-developed reserves.
Depreciation is based on estimated useful life. Reserve
determinations are management's best estimates and generally
are related to economic and operating conditions. Depletion
and depreciation rates are adjusted for future estimated
salvage values.
CLAM property, plant and equipment retirements:
Upon sale or retirement of property, plant and equipment, the
cost and related accumulated depletion, amortization and
depreciation are eliminated from the accounts and the gain or
loss is reflected in income.
CLAM platform abandonment amortization:
Platform abandonment amortization is provided under the unit-
of-production method based upon estimates of proved-developed
reserves. Amortization rates are adjusted for future
estimated abandonment costs. Platform abandonment
amortization is charged to operating expense.
2. Related party transactions
CLAM transactions with related parties consisted of charges
for geological, geophysical and administrative services
rendered by an affiliate under two service contracts and
administrative services rendered by another affilate. Such
charges were approximately $2,183,002, $2,512,536 and
$2,530,608 for 1994, 1993 and 1992, respectively. Salaries
and related social charges included therein amounted to
$1,449,062, $1,685,046 and $1,858,876 for 1994, 1993 and 1992,
respectively.
MaraLou transactions with related parties consisted of charges
for administrative services rendered by an affiliate amounting
to $59,880, $55,800 and $58,200 in 1994, 1993 and 1992,
respectively.
3. Property, plant and equipment
Changes in property, plant and equipment for the years ended
December 31, 1994, 1993 and 1992 are as follows (in thousands
of U.S. dollars):
<CATION>
Balance Additions Dry Hole Balance
12/31/93 (Reductions) Costs 12/31/94
Concession $ 11,678 $ (3,403) $ - $ 8,275
Wells and platforms 262,139 18,689 - 280,828
Incomplete construction 3,278 2,448 - 5,726
Uncompleted wells 17,640 (1,482) 122 16,280
Pipelines 48,439 3,431 - 51,870
Gas processing facilities 5,374 1,145 - 6,519
Furniture and fixtures 1,116 11 - 1,127
$ 349,664 $ 20,839 $ 122 $ 370,625
Depletion and amortization $ 183,645 $ 16,499 $ - $ 200,144
Depreciation-furniture and
fixtures 1,032 73 - 1,105
$ 184,677 $ 16,572 $ - $ 201,249
Net property, plant
and equipment $ 164,987 $ 169,376
Balance Additions Dry Hole Balance
12/31/92 (Reductions) Costs 12/31/93
Concession $ 12,231 $ (553) $ - $ 11,678
Well and platforms 246,086 16,053 - 262,139
Incomplete construction 11,985 (8,707) - 3,278
Uncompleted wells 17,245 1,720 (1,325) 17,640
Pipelines 48,403 36 - 48,439
Gas processing facilities 3,952 1,422 - 5,374
Furniture and fixtures 1,113 3 - 1,116
$ 341,015 $ 9,974 $ (1,325) $ 349,664
Depletion and amortization $ 169,631 $ 14,014 $ - $ 183,645
Depreciation-furniture and
fixtures 945 87 - 1,032
$ 170,576 $ 14,101 $ - $ 184,677
Net property, plant
and equipment $ 170,439 $ 164,987
Balance Additions Dry Hole Balance
12/31/91 (Reductions) Costs 12/31/92
Concession $ 12,231 $ - $ - $ 12,231
Wells and platforms 233,339 12,747 - 246,086
Incomplete construction 15,039 (3,054) - 11,985
Uncompleted wells 15,228 4,540 (2,523) 17,245
Pipelines 42,847 5,556 - 48,403
Gas processing facilities 3,751 201 - 3,952
Furniture and fixtures 1,070 43 - 1,113
$ 323,505 $ 20,033 $ (2,523) $ 341,015
Depletion and amortization $ 154,292 $ 15,339 $ - $ 169,631
Depreciation-furniture and
fixtures 860 85 - 945
$ 155,152 $ 15,424 $ - $ 170,576
Net property, plant
and equipment $ 168,353 $ 170,439
4. Federal and foreign income taxes
MaraLou is a partnership and, therefore, does not pay income
taxes. Since CLAM (wholly owned by MaraLou) is a corporation,
income taxes included in the accompanying consolidated
financial statements have been determined utilizing applicable
domestic and foreign tax rates.
The FASB has issued Statement of Financial Accounting Standard
(SFAS) No. 109, "Accounting for Income Taxes" which superseded
SFAS No. 96, "Accounting for Income Taxes."
SFAS 109 was adopted on January 1, 1993 and requires a change
from the deferred method of accounting for income taxes to the
asset and liability method. Under the new method, deferred
tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statements carrying amounts of existing assets and liabilities
and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates applicable to
those years in which the temporary differences between
financial statement carrying amounts and tax bases are
expected to be recovered or settled. The effect of a change
in tax rates on deferred tax assets and liabilities is
recognized in income in the period when the change is enacted.
Dutch investment incentive premiums (WIR) are credited to
foreign income tax in the year in which they are claimed.
CLAM incurred WIR premium expense of $301,355, $60,331 and
$371,771 in 1994, 1993 and 1992, respectively.
Details of federal and foreign income taxes (in thousands of
U.S. dollars) are as follows:
1994 1993 1992
Current tax expense:
Federal $ (860) $ (2,471) $ 1,063
Foreign 8,779 22,615 13,950
Deferred tax expense (benefit):
Federal 2,673 (2,544) (2,800)
Foreign 6,349 (5,408) 5,311
Total provision for income taxes $16,941 $ 12,192 $17,524
Total income tax expense differed from the amounts computed by
applying the U.S. Federal income tax rate of 35% for 1994 and
1993 and 34% for 1992, respectively, to income before income
taxes of CLAM as a result of the following (in thousands of
U.S. dollars):
1994 1993 1992
Computed "expected" tax expense $ 10,267 $ 9,440 $12,188
Increase (reduction) in income taxes
resulting from:
Foreign tax greater than federal
income tax 4,178 (10,024) 2,668
Increase in deferred tax valuation
allowance 2,852 12,152 2,328
Other (356) 624 340
Provision for income taxes $ 16,941 $ 12,192 $17,524
Temporary differences between the financial statement carrying
amounts and tax bases of assets and liabilities that give rise
to significant portions of the deferred tax assets and
liabilities at December 31, 1994 and 1993 relate to the
following (in thousands of U.S. dollars):
U.S. - Deferred 1994 1993
Deferred Tax Assets:
Foreign tax credit carryover $ - $ 3,805
Benefit for foreign deferred taxes 13,415 6,199
Abandonment accrual 7,354 7,151
Valuation allowance (14,281) (8,860)
Total deferred tax assets $ 6,488 $ 8,295
Deferred Tax Liabilities:
Property, plant and equipment differences
in depreciation and amortization $21,798 $ 20,932
Total deferred tax liabilities $21,798 $ 20,932
Total U.S. - deferred $15,310 $ 12,637
Foreign State Profit Share - Deferred 1994 1993
Deferred Tax Assets:
Abandonment accrual $ 2,809 $ 4,769
Morgan loan currency revaluation 270 5,287
Valuation allowance (723) (3,292)
Total deferred tax assets $ 2,356 $ 6,764
Deferred Tax Liabilities:
Property, plant and equipment differences
in depreciation and amortization $15,771 $ 12,899
Total deferred tax liabilities $15,771 $ 12,899
Total Foreign State Profit Share - deferred $13,415 $ 6,135
The Company's 1994 and 1993 current tax liability was
determined on a regular tax basis. A minimum tax carryforward
of $339,175 remains at December 31, 1994.
5. CLAM foreign currency translation adjustment
As of January 1, 1983 CLAM adopted Statement of Financial
Accounting Standards No. 52, "Foreign Currency Translation"
(SFAS No. 52), under which the functional currency is deemed
to be the Dutch guilder. Effective January 1, 1987 CLAM
changed its functional currency from the Dutch guilder to the
U.S. dollar. The change was precipitated by the significant
effect on CLAM's operation of a new dollar-driven gas sales
contract which was effective January 1, 1987 and the Tax
Reform Act of 1986. In accordance with SFAS No 52, there is
no restatement of prior years' financial statements and the
translated amounts for nonmonetary assets as of December 31,
1986 have become the accounting basis for those assets in the
year of the change.
6. Debt
On July 25, 1985 MaraLou and CLAM entered into a revolving
credit agreement, which was amended and restated as of June
19, 1992, with a syndicate of major international banks to
fund the purchase by MaraLou of CLAM shares previously owned
by Netherlands-Cities Service, Inc. and to provide working
capital for CLAM. The banks' total commitment as of
December 31, 1994 and December 31, 1993 was $110,000,000.
Interest is paid, at the borrower's option, based on the prime
rate, the London Interbank Offered Rate (LIBOR), or an
adjusted CD rate. A contractual margin is added to LIBOR and
CD based borrowings. The all-in interest rates for CLAM for
December 31, 1994 and December 31, 1993 were 6.9375% and
3.9375%, respectively. During the revolving credit period,
the borrowers are obligated to pay a commitment fee of 1/4% on
the unused committed portion of the facility. All of the CLAM
common stock held by MaraLou has been pledged as security for
the facility. In addition, under certain circumstances
MaraLou can exercise an option to purchase the shares held by
LL&E Netherlands Petroleum Company and Marathon Petroleum
Netherlands, Ltd. for a nominal amount. The option agreement
has been assigned to the banks as security for the facility.
The credit agreement permits CLAM and MaraLou to incur total
debt up to an agreed borrowing base which at December 31, 1994
and December 31, 1993 was $132,000,000 and $145,000,000. The
agreement provides that the borrowing base is reduced
periodically over the term of the facilty which is currently
scheduled to expire on December 31, 2000. The borrowing base
and the scheduled reductions may be adjusted based on a
redetermination of the net present value of the projections of
certain cash flows included in an Engineering Report prepared
by petroleum engineers.
The outstanding balances for MaraLou and CLAM, respectively,
were $-0- and $96,000,000, at December 31, 1994 of which $-0-
was due within one year. The outstanding balances for MaraLou
and CLAM, respectively, were $-0- and $87,800,000 at
December 31, 1993. At December 31, 1994, the required
reductions to the borrowing base in each of the next five
years are $-0- in 1995, $-0- in 1996, $8,000,000 in 1997,
$29,000,000 in 1998, $30,000,000 in 1999 and $29,000,000 in
2000.
CLAM has an unsecured combined short-term loan and overdraft
facility of Dfl. 80,000,000 ($46,101,539 at year-end exchange
rate). On December 31, 1994 and December 31, 1993 the
outstanding balances relating to this facility were $-0-.
Interest rates are determined at the time borrowings are made.
7. Annual evaluation of gas reserves
Under the provisions of the Joint Development Operating
Agreement to which CLAM is a party, an annual estimate of gas
reserves is to be made and agreed upon by the Area Management
Committee. Based upon such estimate, each participant's
investment in the area properties, as defined, is to be
adjusted so that a participant's investment is in proportion
to its interest in the remaining reserves. Adjustments to the
investments are made in cash in the year following the date
the reserve revision is agreed upon.
In 1992, the Area Management Committee agreed to freeze each
participant's interest through 1994, at the level agreed upon
in 1992. However, in 1994 new entitlements were agreed upon,
effective January 1, 1994. CLAM made a cash payment of
$15,382,204 to equalize past investment. New entitlement
estimates will be agreed upon in 1995.
8. Reserves of oil and gas (unaudited)
CLAM's share of proven gas reserves at January 1, 1995 and
1994 are 261,990 MMCF and 317,737 MMCF, respectively.
9. Major customer
CLAM has one major customer from which it derives 97% of its
sales revenue. CLAM was required under its production license
to offer its production first to this customer, which is
partially owned by The Netherlands government. Production is
sold to this customer under five contracts representing
various partnership interests and gas qualities.
10. Net profits interest agreement
CLAM entered into an agreement dated November 1, 1981 which
requires CLAM to pay a portion of its net profits ("net
profits interest") to an unrelated party in exchange for a
7-1/2% participation interest in certain blocks. The "net
profits interest" is equal to one twenty-fourth (1/24) of
CLAM's revenues from the contract area, after various
deductions, as defined in the agreement.
11. Issuance of production licenses
In March 1990, a production license was granted by the
Minister of Economics Affairs of the Netherlands covering the
L12a and L12b/L15b blocks. As a result, the Dutch Government,
through Energie Beheer Nederland (EBN) (a Dutch company wholly
owned by the Dutch Government) exercised its option to
participate 40% in the L12a block and 50% in the L12b/L15b
block. CLAM was subsequently reimbursed $10,628,572 during
1990, all of which was included in income because there were
costs associated with these blocks which had been written-off
in prior years. Components of the reimbursement were:
Exploration well cost (previously
written off as dry wells) $ 5,595,076
Exploration administrative expense 1,818,220
Interest 3,215,276
Total reimbursement $10,628,572
In 1991, it was determined that the portion of the above noted
reimbursement allocable to trapping unit L12-FC, within blocks
L12b/L15b, would be refunded to EBN as production on this
trapping unit is not expected to commence within the 48-month
requirement stipulated by the contractual agreement with EBN
(the Agreement). The refundable amount, which CLAM expected
to repay in 1994, was recorded as a long-term receivable of
$3.6 million, interest expense of $1.5 million and an accrued
liability of $5.1 million. The Agreement calls for EBN to
reimburse the funds to CLAM net of interest upon first
production from trapping unit L12-FC, which is expected to
occur in 1997.
In 1992, it was determined that the portion of the above noted
reimbursement allocable to trapping units L12-FA and L12-FB,
within blocks L12a and L12b/L15b, would be refunded to EBN as
production on these trapping units are not expected to
commence within the 48-month requirement stipulated by the
Agreement. The refundable amount for L12-FA and L12-FB, which
CLAM expected to repay in 1994, was recorded as a long-term
receivable of $0.5 and $1.6 million, respectively, interest
expense $0.2 million and $0.6 million, respectively and an
accrued liability of $0.7 million and $2.2 million,
respectively. The Agreement calls for EBN to reimburse the
respective funds to CLAM net of interest upon first production
from trapping units L12-FA and L12-FB, which is expected to
occur in 2000 and 1998, respectively.
In 1994, the contractual agreement with EBN (the Agreement)
was renegotiated with the result being that the refundable
amounts for the L12-FB and L12-FC trapping units will have to
be repaid by December 31, 1999 unless production has commenced
prior to this date. Additionally, it was agreed there is no
repayment obligation for the L12-FA trapping unit, and
resulting in a reversal of the associated long-term
receivable, interest expense and accrued liability.
12. Disclosures about fair value of financial instruments
Cash and Cash Equivalents, Receivables, Due from Operator of
Joint Venture, Due to Affiliated Company, Accounts Payable,
and Due to Operator of Joint Venture
- The carrying amount approximates fair value because of
the short maturity of these instruments.
Long-Term Receivable
- The estimated fair value of the Company's long-term
receivable is as follows (in thousands of U.S. dollars):
At December 31, 1994
Carrying Estimated
Amount Fair Value
Long-term receivable $5,774 $3,631
The fair value of the long-term receivable was based on
discounted cash flows.
Long-Term Debt Due to Banks
- The carrying amount approximates fair value because of
the variable rate of interest associated with this debt.
Derivatives
- MaraLou has no derivative financial instruments.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information relating to directors of the Registrant will be
contained in the definitive Proxy Statement for its Annual Meeting
of Stockholders to be held on May 11, 1995, which the Registrant
will file pursuant to Regulation 14A not later than 120 days after
December 31, 1994, and such information is incorporated herein by
reference in accordance with General Instruction G(3) of Form 10-K.
Information relating to executive officers of the Registrant
appears at page 25 of this Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
Information relating to the compensation of the Registrant's
executive officers and directors will be contained in the
definitive Proxy Statement referred to above in Item 10. -
"Directors and Executive Officers of the Registrant," and such
information is incorporated herein by reference in accordance with
General Instruction G(3) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
Information relating to beneficial ownership of securities
will be contained in the definitive Proxy Statement referred to
above in Item 10. - "Directors and Executive Officers of the
Registrant," and such information is incorporated herein by
reference in accordance with General Instruction G(3) of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information relating to transactions with management and
others and certain business relationships regarding directors will
be contained in the definitive Proxy Statement referred to above in
Item 10. - "Directors and Executive Officers of the Registrant,"
and such information is incorporated herein by reference in
accordance with General Instruction G(3) of Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORMS 8-K.
(a)(1) Financial Statements - the information
required hereunder is included in Item 8. -
"Financial Statements and Supplementary Data."
(a)(2) Financial Statement Schedules - all financial
statement schedules are omitted as the
required information is inapplicable or the
information is presented in the consolidated
financial statements or related notes.
(a)(3) Index to Exhibits - the information required
hereunder is included herein.
(b) Reports on Form 8-K - no reports on Form 8-K
were filed during the quarter ended December
31, 1994.
THE LOUISIANA LAND AND EXPLORATION COMPANY
AND SUBSIDIARIES
Index to Exhibits
The following Exhibits have been filed with the Securities and
Exchange Commission:
Exhibit 3(a) Certificate of Incorporation (Incorporated by
reference to Exhibit 1-3(a) to the Registrant's
Registration Statement No. 2-45541 on Form S-1.);
Articles Supplementary pursuant to Section 3-
603(d)(4) of the Maryland General Corporation Law
(Incorporated by reference to Exhibit 3(b) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1983 - Commission File No.
1-959.); Articles of Amendment of Charter dated May
30, 1985 (Incorporated by reference to Exhibit 3(b)
to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1985 - Commission File
No. 1-959.); Articles of Amendment of Charter dated
May 12, 1988 (Incorporated by reference to Exhibit
3(c) to the Registrant's Form 8 dated April 24,
1989 - Commission File No. 1-959.).
Exhibit 3(b) By-Laws (Incorporated by reference to Exhibit (1)
to the Registrant's Current Report on Form 8-K
dated October 1, 1989 - Commission File No. 1-
959.).
Exhibit 4(a) Rights Agreement dated as of May 25, 1986 among the
Registrant and The Bank of New York (as Rights
Agent) - (Incorporated by reference to Exhibit 4(a)
to the Registrant's Current Report on Form 8-K
dated May 25, 1986 - Commission File No. 1-959.).
Exhibit 4(b) Indenture dated as of June 15, 1992 among the
Registrant and Texas Commerce Bank National
Association (as Trustee) - (Incorporated by
reference to Exhibit 4.1 to the Registrant's
Registration Statement No. 33-50991 on Form S-3, as
amended.).
Exhibit 10(a) Form of Termination Agreement with Senior
Management Personnel (Incorporated by reference to
Exhibit 10(b) to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1982 -
Commission File No. 1-959.).
(continued)
THE LOUISIANA LAND AND EXPLORATION COMPANY
AND SUBSIDIARIES
Index to Exhibits
Exhibit 10(b) The Louisiana Land and Exploration Company 1982
Stock Option Plan as adopted (Incorporated by
reference to Exhibit A to the Registrant's
definitive Proxy Statement dated March 26, 1982.)
and the amendment thereto dated December 8, 1982
(Incorporated by reference to Exhibit 10(c) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1982 - Commission File No.
1-959.).
Exhibit 10(c) The Louisiana Land and Exploration Company 1988
Long-Term Stock Incentive Plan as amended
(Incorporated by reference to Exhibit A to the
Registrant's definitive Proxy Statement dated March
22, 1993.).
Exhibit 10(d) Deferred Compensation Plan for Directors
(Incorporated by reference to Exhibit 10(d) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1982 - Commission File No.
1-959.).
Exhibit 10(e) Pension Agreement dated December 27, 1994.
Exhibit 10(f) The Louisiana Land and Exploration Company 1990
Stock Option Plan for Non-Employee Directors as
adopted (Incorporated by reference to Exhibit A to
the Registrant's definitive Proxy Statement dated
March 26, 1990.).
Exhibit 10(g) Form of The Louisiana Land and Exploration Company
Deferred Compensation Arrangement for Selected Key
Employees (Incorporated by reference to Exhibit
10(i) to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1990 -
Commission File No. 1-959.).
Exhibit 10(h) Retirement Plan for Directors of The Louisiana Land
and Exploration Company dated March 1, 1987
(Incorporated by reference to Exhibit 10(j) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1990 - Commission File No.
1-959.).
(continued)
THE LOUISIANA LAND AND EXPLORATION COMPANY
AND SUBSIDIARIES
Index to Exhibits
Exhibit 10(i) The LL&E Special Termination Benefit Plan
(Incorporated by reference to Exhibit 10(j) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1992 - Commission File No.
1-959.).
Exhibit 10(j) The LL&E Supplemental Excess Plan (Incorporated by
reference to Exhibit 10(k) to the Registrant's
Annual Report on Form 10-K for the year ended
December 31, 1992 - Commission File No. 1-959.).
Exhibit 10(k) Form of Compensatory Benefits Agreement
(Incorporated by reference to Exhibit 10(l) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1992 - Commission File No.
1-959.).
Exhibit 10(l) Amended and Restated Credit Agreement dated as of
August 19, 1994 (the Credit Agreement) among the
Registrant, the Banks listed therein, Morgan
Guaranty Trust Company of New York, as Agent, and
Texas Commerce Bank National Association and
NationsBank of Texas, N.A., as Co-Agents.
Exhibit 10(m) Amendment No. 1 to the Credit Agreement dated as of
January 23, 1995 among the Registrant, the Banks
listed on the signature pages thereof and Morgan
Guaranty Trust Company of New York, as Agent.
Exhibit 11 Computation of Primary and Fully Diluted Earnings
(Loss) Per Share.
Exhibit 21 Subsidiaries of the Registrant.
Exhibit 23 Consent of Experts.
Exhibit 24 Powers of Attorney.
Exhibit 27 Financial Data Schedule.
Certain debt instruments have not been filed. The Company agrees
to furnish a copy of such agreement(s) to the Commission upon
request.
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.
THE LOUISIANA LAND AND EXPLORATION
COMPANY
(Registrant)
Date: March 9, 1995 By /s/ Frederick J. Plaeger, II
__________________________________
Frederick J. Plaeger, II
General Counsel and Corporate
Secretary
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
Date: March 9, 1995 *H. Leighton Steward
_____________________________________
H. Leighton Steward
Director, Chairman of the Board,
President and Chief Executive Officer
(Principal Executive Officer)
Date: March 9, 1995 *Leland C. Adams
_____________________________________
Leland C. Adams
Director
Date: March 9, 1995 *Richard A. Bachmann
_____________________________________
Richard A. Bachmann
Director, Executive Vice President,
Finance and Administration
(Principal Financial Officer)
Date: March 9, 1995 *John F. Greene
_____________________________________
John F. Greene
Director, Executive Vice President,
Exploration and Production
Date: March 9, 1995 *Eamon M. Kelly
_____________________________________
Eamon M. Kelly
Director
Date: March 9, 1995 *Kenneth W. Orce
_____________________________________
Kenneth W. Orce
Director
Date: March 9, 1995 *Victor A. Rice
_____________________________________
Victor A. Rice
Director
Date: March 9, 1995 *Orin R. Smith
_____________________________________
Orin R. Smith
Director
Date: March 9, 1995 *Arthur R. Taylor
_____________________________________
Arthur R. Taylor
Director
Date: March 9, 1995 *W. R. Timken, Jr.
_____________________________________
W. R. Timken, Jr.
Director
Date: March 9, 1995 *Carlisle A.H. Trost
_____________________________________
Carlisle A.H. Trost
Director
Date: March 9, 1995 *E. L. Williamson
_____________________________________
E. L. Williamson
Director
Date: March 9, 1995 *Jerry D. Carlisle
_____________________________________
Jerry D. Carlisle
Vice President and Controller
(Principal Accounting Officer)
*/s/ Frederick J. Plaeger, II
_________________________________________
Frederick J. Plaeger, II
General Counsel and Corporate Secretary
(As attorney-in-fact for each of the
persons indicated)
________________________________________________________________
________________________________________________________________
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
__________________________
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
__________________________
THE LOUISIANA LAND AND EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
EXHIBITS
________________________________________________________________
________________________________________________________________
THE LOUISIANA LAND AND EXPLORATION COMPANY
AND SUBSIDIARIES
Index to Exhibits
(Item 14(a)(3))
The following Exhibits have been filed with the Securities and
Exchange Commission:
Exhibit 3(a) Certificate of Incorporation (Incorporated by
reference to Exhibit 1-3(a) to the Registrant's
Registration Statement No. 2-45541 on Form S-1.);
Articles Supplementary pursuant to Section 3-
603(d)(4) of the Maryland General Corporation Law
(Incorporated by reference to Exhibit 3(b) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1983 - Commission File No.
1-959.); Articles of Amendment of Charter dated May
30, 1985 (Incorporated by reference to Exhibit 3(b)
to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1985 - Commission File
No. 1-959.); Articles of Amendment of Charter dated
May 12, 1988 (Incorporated by reference to Exhibit
3(c) to the Registrant's Form 8 dated April 24,
1989 - Commission File No. 1-959.).
Exhibit 3(b) By-Laws (Incorporated by reference to Exhibit (1)
to the Registrant's Current Report on Form 8-K
dated October 1, 1989 - Commission File No. 1-
959.).
Exhibit 4(a) Rights Agreement dated as of May 25, 1986 among the
Registrant and The Bank of New York (as Rights
Agent) - (Incorporated by reference to Exhibit 4(a)
to the Registrant's Current Report on Form 8-K
dated May 25, 1986 - Commission File No. 1-959.).
Exhibit 4(b) Indenture dated as of June 15, 1992 among the
Registrant and Texas Commerce Bank National
Association (as Trustee) - (Incorporated by
reference to Exhibit 4.1 to the Registrant's
Registration Statement No. 33-50991 on Form S-3, as
amended.).
Exhibit 10(a) Form of Termination Agreement with Senior
Management Personnel (Incorporated by reference to
Exhibit 10(b) to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1982 -
Commission File No. 1-959.).
(continued)
THE LOUISIANA LAND AND EXPLORATION COMPANY
AND SUBSIDIARIES
Index to Exhibits (continued)
(Item 14(a)(3))
Exhibit 10(b) The Louisiana Land and Exploration Company 1982
Stock Option Plan as adopted (Incorporated by
reference to Exhibit A to the Registrant's
definitive Proxy Statement dated March 26, 1982.)
and the amendment thereto dated December 8, 1982
(Incorporated by reference to Exhibit 10(c) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1982 - Commission File No.
1-959.).
Exhibit 10(c) The Louisiana Land and Exploration Company 1988
Long-Term Stock Incentive Plan as amended
(Incorporated by reference to Exhibit A to the
Registrant's definitive Proxy Statement dated March
22, 1993.).
Exhibit 10(d) Deferred Compensation Plan for Directors
(Incorporated by reference to Exhibit 10(d) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1982 - Commission File No.
1-959.).
Exhibit 10(e) Pension Agreement dated December 27, 1994.
Exhibit 10(f) The Louisiana Land and Exploration Company 1990
Stock Option Plan for Non-Employee Directors as
adopted (Incorporated by reference to Exhibit A to
the Registrant's definitive Proxy Statement dated
March 26, 1990.).
Exhibit 10(g) Form of The Louisiana Land and Exploration Company
Deferred Compensation Arrangement for Selected Key
Employees (Incorporated by reference to Exhibit
10(i) to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1990 -
Commission File No. 1-959.).
Exhibit 10(h) Retirement Plan for Directors of The Louisiana Land
and Exploration Company dated March 1, 1987
(Incorporated by reference to Exhibit 10(j) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1990 - Commission File No.
1-959.).
(continued)
THE LOUISIANA LAND AND EXPLORATION COMPANY
AND SUBSIDIARIES
Index to Exhibits (continued)
(Item 14(a)(3))
Exhibit 10(i) The LL&E Special Termination Benefit Plan
(Incorporated by reference to Exhibit 10(j) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1992 - Commission File No.
1-959.).
Exhibit 10(j) The LL&E Supplemental Excess Plan (Incorporated by
reference to Exhibit 10(k) to the Registrant's
Annual Report on Form 10-K for the year ended
December 31, 1992 - Commission File No. 1-959.).
Exhibit 10(k) Form of Compensatory Benefits Agreement
(Incorporated by reference to Exhibit 10(l) to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1992 - Commission File No.
1-959.).
Exhibit 10(l) Amended and Restated Credit Agreement dated as of
August 19, 1994 (the Credit Agreement) among the
Registrant, the Banks listed therein, Morgan
Guaranty Trust Company of New York, as Agent, and
Texas Commerce Bank National Association and
NationsBank of Texas, N.A., as Co-Agents.
Exhibit 10(m) Amendment No. 1 to the Credit Agreement dated as of
January 23, 1995 among the Registrant, the Banks
listed on the signature pages thereof and Morgan
Guaranty Trust Company of New York, as Agent.
Exhibit 11 Computation of Primary and Fully Diluted Earnings
(Loss) Per Share.
Exhibit 21 Subsidiaries of the Registrant.
Exhibit 23 Consent of Experts.
Exhibit 24 Powers of Attorney.
Exhibit 27 Financial Data Schedule.
Certain debt instruments have not been filed. The Company agrees
to furnish a copy of such agreement(s) to the Commission upon
request.