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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
________________
(Mark One) FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 0-7062
Noble Affiliates, Inc.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Delaware 73-0785597
(STATE OF INCORPORATION) (I.R.S. EMPLOYER
IDENTIFICATION NUMBER)
110 West Broadway
Ardmore, Oklahoma 73401
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code:
(405) 223-4110
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange on
Title of Each Class Which Registered
------------------- ----------------
Common Stock, $3.33-1/3 par value New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes /X/ No _____
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the 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/
Aggregate market value of Common Stock held by nonaffiliates as of
March 11, 1996: $1,329,639,933.
Number of shares of Common Stock outstanding as of March 11, 1996:
50,314,692.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below are documents parts of which are incorporated herein by
reference and the part of this report into which the document is incorporated:
(1) 1995 annual report to the shareholders - Parts I and II.
(2) Proxy statement for the 1996 annual meeting of shareholders -
Part III.
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Oil and Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Exploration Activities . . . . . . . . . . . . . . . . . . . . . 1
Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Production Activities. . . . . . . . . . . . . . . . . . . . . . 4
Marketing. . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Regulation and Risks . . . . . . . . . . . . . . . . . . . . . . 5
Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Employees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Offices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Oil and Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . 11
Executive Officers of the Registrant . . . . . . . . . . . . . . . 12
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . 13
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations. . . . . . . . . . . . . . . . . . . . . . . 13
Item 8. Financial Statements and Supplementary Data. . . . . . . . . . . . 13
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.. . . . . . . . . . . . . . . . . . . . . . . 13
Item 10. Directors and Executive Officers of the Registrant.. . . . . . . . 13
Item 11. Executive Compensation.. . . . . . . . . . . . . . . . . . . . . . 13
Item 12. Security Ownership of Certain Beneficial Owners and Management.. . 14
Item 13. Certain Relationships and Related Transactions.. . . . . . . . . . 14
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 14
(i)
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PART I
ITEM 1. BUSINESS.
GENERAL
Noble Affiliates, Inc. is a Delaware corporation organized in 1969.
The Registrant is principally engaged, through its subsidiaries, in the
exploration, production and marketing of oil and gas. In this report, unless
otherwise indicated or the context otherwise requires, the "Company" or the
"Registrant" refers to Noble Affiliates, Inc. and its subsidiaries.
OIL AND GAS
The Registrant's wholly owned subsidiary, Samedan Oil Corporation
("Samedan"), has been engaged in the exploration for and production of oil and
gas since 1932. Samedan conducts its exploration and production operations
throughout the major basins in the United States, including the Gulf of Mexico,
and in foreign jurisdictions, primarily in Canada and Africa. For information
regarding Samedan's oil and gas properties, see "Item 2 - Properties - Oil and
Gas" on pages 7 through 11 of this report. The Registrant's wholly owned
subsidiary, Noble Gas Marketing, Inc. ("NGM"), markets the Company's natural gas
as well as third-party gas. For more information regarding NGM's operations,
see "Item 1 - Business - Oil and Gas - Marketing" on pages 4 and 5 of this
report. The Registrant's wholly owned subsidiary, Noble Trading, Inc. ("NTI"),
markets a portion of the Company's oil as well as third-party oil. For more
information regarding NTI's operations, see "Item 1 - Business - Oil and Gas -
Marketing" on pages 4 and 5 of this report.
In this report, unless the context otherwise requires, Samedan refers
to Samedan Oil Corporation and its subsidiaries and NGM refers to Noble Gas
Marketing, Inc. and its subsidiary. In this report, quantities of oil are
expressed in barrels ("bbls"), and quantities of natural gas are expressed in
thousands of cubic feet ("Mcf"), millions of cubic feet ("MMcf") or billions of
cubic feet ("Bcf").
EXPLORATION ACTIVITIES
Samedan, by itself or through various arrangements with others,
investigates potential oil and gas properties, seeks to acquire exploration
rights in areas of interest and conducts exploratory activities, including
geophysical and geological evaluation and exploratory drilling, where
appropriate, on properties for which it acquired such exploration rights.
Samedan has been engaged in exploration and development of oil and gas
reserves in federal and state waters offshore Texas and Louisiana since 1968 and
has remained active in these areas of the Gulf of Mexico throughout the past 27
years during which it has drilled, or participated in the drilling of (through
December 31, 1995), 702 gross wells. In 1995, Samedan drilled or participated
in the drilling of 16 exploratory wells (7.0 net) and 37 development wells (17.4
net) in federal and state waters offshore Texas and Louisiana. Of the 53 gross
wells drilled, 40 (18.4 net) were completed as productive wells and 13 (5.9 net)
were abandoned as dry holes. The Registrant intends to remain active in these
areas of the Gulf of Mexico. As of December 31, 1995, the Registrant had 82
undeveloped leases in the Gulf of Mexico, with expiration dates ranging from
1996 to 2001, in which the Registrant currently intends to conduct future
exploration activities.
The following paragraphs in this "Exploration Activities" section
describe significant domestic activities in 1995.
GULF OF MEXICO. Samedan drilled two wells on its Vermilion
362/363/371 prospect during 1995, bringing to nine the total number of gross
wells drilled on the 44 percent owned field. The Vermilion 363 #2 well
encountered 41 feet of gas/condensate pay in four zones. The Vermilion 371 #5
well was also drilled in 1995 and encountered 86 feet of gas/condensate pay in
five zones.
A production platform was installed on Vermilion 371 in July 1995.
Three of the wells on the platform are completed and were producing
approximately 36 MMcf of gas and 2,000 bbls of oil/condensate per day at
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December 31, 1995. The remaining two wells on Vermilion 371 are expected to be
completed and on line by March 1996.
A second production platform for Vermilion 362/363 is scheduled to be
installed in May 1996. Four wells on the platform are expected to be completed
and on line by August 1996.
Samedan acquired a 50 percent working interest in the Vermilion
314/315 prospect in August 1995 and drilled two wells from an existing platform.
The Vermilion #A-8 well encountered 85 feet of pay in two zones. The Vermilion
#A-9 well encountered 80 feet of pay in three zones. At year end the wells were
producing an aggregate of 6 MMcf of gas per day.
Samedan also completed 3 wells in its 50 percent owned Vermilion
332/333 field in the fourth quarter of 1995. At year end the field was
producing 2,000 bbls of oil and 2.5 MMcf of gas per day.
The Company participated in 1995 with a 25 percent working interest in
drilling four wells on its Vermilion 279 prospect. Three successful wells were
drilled and oil and gas pay was encountered in multiple zones. Production
facilities are currently being constructed and are scheduled to be installed in
the second quarter of 1996 with first production scheduled during the third
quarter of 1996.
Two wells were drilled on Samedan's 100 percent owned High Island A-
547 prospect in 1995. The #B-6 well encountered 378 feet of oil and gas pay in
nine zones. The #B-7 well encountered 164 feet of oil and gas pay in six zones.
Two gas/condensate wells were completed and producing at year end approximately
12.7 MMcf of gas and 40 bbls of condensate per day. Installation of oil
production facilities on the platform is currently underway.
During 1995 Samedan completed two wells on its 100 percent owned High
Island A-550 property. At year end this field was producing 22 MMcf of gas and
830 bbls of oil/condensate per day.
Production commenced in October 1995 on Samedan's 83.3 percent owned
High Island A-281 field. At year end approximately 15.4 MMcf of gas per day was
being produced from two wells.
Six additional wells were completed in 1995 on Samedan's 70.4 percent
owned East Cameron 331/332 field. A total of 11 wells were producing from this
field, which was producing approximately 64.5 MMcf of gas and 4,270 bbls of
oil/condensate per day at year end 1995.
In 1995 Samedan drilled three wells on its 85 percent owned East
Cameron 320 lease, which is immediately north of the East Cameron 331/332 field.
The wells encountered oil and gas pay ranging in size from 64 to 125 feet.
Production facilities have been installed and first production is scheduled for
early 1996.
One additional well was drilled during 1995 on Samedan's 25 percent
owned Green Canyon 136 field. Production from the field at year end was 60 MMcf
of gas and 700 bbls of condensate per day.
Completion operations were underway at year end on Samedan's 66
percent owned Garden Banks 240 #3 well which should be capable of delivering
approximately 25 MMcf of gas per day when operational.
During 1995 Samedan drilled and logged 68 feet of gas pay in its South
Timbalier 172 #6 well, in which Samedan owns a 100 percent working interest.
The well, along with the #5 well, should be tied into the pipeline during the
first quarter of 1996. In addition, during 1995 Samedan drilled and logged 112
feet of gas pay in its South Timbalier 192 #2 well in which Samedan owns a 100
percent working interest. Production from this well is expected to commence in
the third quarter of 1996.
In July 1995 Samedan purchased the full working interest in West
Cameron 599/600 for $5.3 million. Development plans include installing
production facilities and drilling two development wells. Samedan also intends
to drill two exploratory wells on the property in 1996. The Company estimates
proved reserves associated with the purchase to be 35 Bcf of gas.
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In October 1995 Samedan also purchased the full working interest in
Galveston 150L and High Island A-325 and a 55 percent working interest in Eugene
Island 286 for $22.6 million. The properties are in various stages of
development and will require additional development expenditures estimated at
$13 million. The Company estimates proved reserves associated with this
acquisition to be 40.5 Bcf of gas and 35,000 bbls of condensate. Eugene Island
286 and High Island A-325 each are expected to commence production in the second
quarter of 1996, and Galveston 150L in third quarter of 1996.
During 1995, Samedan commenced oil and gas production from the
following fields: Vermilion 362/363/371, Vermilion 332/333, High Island A-
547/548, Vermilion 314/315, High Island A-550, High Island A-281 and Green
Canyon 136.
DOMESTIC ONSHORE. Samedan participated in drilling 90 gross wells in
the Niobrara formation on acreage located in northeastern Colorado. The
Company's average working interest in the wells is 75 percent. Seventy of the
wells drilled were completed as gas wells, resulting in a 78 percent success
ratio.
In October, Noble Gas Pipeline, Inc. completed the installation of its
16.6 mile gathering system and compressor station. The system connects 71 of
Samedan's gas wells to an interstate pipeline. At year end, the Company was
producing approximately 5 MMcf of gas per day, net to the Company's interest,
through the system. Installation of another gas gathering system in the area is
being evaluated for 1996.
In Caddo County, Oklahoma, Samedan made a gas/condensate discovery in
the Springer-Cunningham formation. The Zipse #2-12 well, in which the Company
owns a 50 percent working interest, was completed at the rate of 4.1 MMcf of gas
and 100 bbls of condensate per day. At year end, Samedan was completing an
offset well, the Harper #1, in which it owns a 40.6 percent working interest.
Another offset, the Samuel #1-2, in which Samedan owns a 25 percent working
interest, commenced production in January 1996.
Samedan participated in drilling two oil wells in Wyoming during 1995.
The Duvall Ranch #2-4 well, Campbell County, was completed at the rate of 348
bbls of oil per day. Samedan owns a 100 percent working interest in the well.
Also in Campbell County, Samedan completed the Kuehne Ranch #9 well which flowed
at the rate of 100 bbls per day. Installation of a pumping unit is expected to
increase the production rate to 450 bbls of oil per day. Samedan owns an 86
percent working interest in the well.
In October 1995, Samedan received the necessary approvals to unitize
the Angell Prospect, Meade County, Kansas and to proceed with installation of
waterflood facilities. Construction was virtually complete at year end and
water injection of 2,000 barrels per day is expected to commence in early 1996.
Samedan owns a 100 percent working interest in the unit.
In south central Oklahoma, Samedan commenced the installation of
waterflood facilities on the Hoover Unit. Necessary approvals were received in
December 1995 and water injection is expected to commence in April 1996.
Samedan owns a 100 percent working interest in the unit, and expects to remain
active in seeking out opportunities to install and operate other oil waterflood
units.
Four infill wells were drilled in the Company's 58.7 percent owned
South Central Robertson Unit in Gaines County, Texas. The unit averaged
approximately 3,200 bbls of oil per day during the year, which is an 11.6
percent increase over 1994. In southern Oklahoma, Samedan drilled nine infill
wells in its Wildcat Jim Penn Unit. The unit, in which Samedan owns a 76.5
percent, increased production 14 percent to 1,030 bbls per day in 1995.
Offsetting and outside the Wildcat Jim Penn Unit, Samedan drilled five
oil wells in the Hoxbar formation. The Company owns an average working interest
of 96.6 percent in the wells, which were producing 175 bbls of oil per day at
year end. A waterflood feasibility study for the wells is currently underway.
During 1995, the Company made a gas discovery in Iberville Parish,
Louisiana. The SL 14720 well, in which the Company owns a 33 percent working
interest, tested 4 MMcf of gas and 80 bbls of condensate per day. A pipeline
connection is expected to be completed in March 1996.
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CANADA. During 1995, Samedan Oil of Canada, Inc., a wholly owned
subsidiary of Samedan ("Samedan-Canada") participated in 8 exploratory wells
(4.5 net) and 11 development wells (5.6 net) with interests ranging from 14 to
100 percent. A total of 11 wells (6.3 net) were successfully completed in 1995.
EQUATORIAL GUINEA. Samedan purchased an additional 4.8 percent
working interest in the Alba field, effective May 1995, for $3.8 million. The
field, in which Samedan owns a total working interest of 34.8 percent, produced
an average of 6,400 bbls of condensate per day for the year.
Construction of an LPG plant in the Alba field is underway to enhance
recovery of liquids. The plant is estimated to cost $18.9 million, and is
expected to be completed by the end of 1996. When fully operational, the plant
is expected to recover 2,400 bbls of LPG and 500 additional bbls of condensate
per day.
Samedan expects to drill two exploratory wells during 1996 on oil
prospects delineated by 3-D seismic interpretation.
TUNISIA. Samedan drilled two non-commercial wells on its 50 percent
owned Zelfa Prospect. As such, Samedan is unable to go forward with
development. Accordingly, the Company charged off $7.5 million to exploration
expense.
Oil and gas production has commenced from Samedan's 28.3 percent owned
Zinnia Prospect, located onshore Tunisia. At year end, two wells were producing
6 MMcf of gas and 200 bbls of oil/condensate per day.
Samedan's 50 percent owned Tazerka oil field produced an average of
1,730 bbls of oil per day during 1995. It continues to generate positive cash
flow even though it is in the last stages of its economic life.
Due to the Company's lack of success in exploratory drilling, the
Company intends to dispose of its interests in Tunisia.
ACQUISITIONS
Also in 1995, Samedan spent $9.7 million on acquisitions of unproved
properties. These properties were acquired primarily through domestic onshore
lease acquisitions, various offshore lease sales and Canadian land sales.
PRODUCTION ACTIVITIES
As of December 31, 1995, Samedan owned approximately 1,895 net
producing oil and gas wells in the United States and Canada and approximately
3.3 net producing oil and gas wells in other foreign jurisdictions. Net
production of oil (including condensate and natural gas liquids), excluding
royalty sales, totaled 9,136,312 bbls in 1995 compared to 8,081,047 bbls in
1994. Net production of natural gas, excluding royalty sales, totaled
96,984,816 Mcf in 1995 compared to 87,729,371 Mcf in 1994.
Samedan operates approximately 32 percent of the gross oil and gas
wells in which it has an interest, with the remainder operated by others under
operating agreements customarily used in the industry.
MARKETING
On January 13, 1994, the Company formed a wholly-owned subsidiary,
Noble Gas Marketing, Inc., for the purpose of seeking out opportunities to
enhance the value of the Company's gas by marketing directly to end users, as
well as accumulating gas to be sold to gas marketers and pipelines. NGM is also
actively involved in the purchase and sale of gas from other producers. Such
third party gas may be purchased from non-operators who own working interests in
the Company's wells, or from other producers' properties in which the Company
may not own an interest. NGM, through its wholly-owned subsidiary, Noble Gas
Pipelines, Inc., engages in the installation, purchase and operation of gas
gathering systems.
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Samedan has a gas sales contract with NGM, whereby Samedan is paid an
index price for all gas sold to NGM. NGM records sales, including hedging
transactions, as gathering, marketing and processing revenues. NGM records as
cost of sales in gathering, marketing and processing costs, the amount paid to
Samedan and third parties. All intercompany sales and costs have been
eliminated.
Oil produced by the Company is sold to various purchasers in the
United States, Canada and other foreign locations at various prices depending on
the location and quality of the oil. The Company has no long-term contracts
with purchasers of its oil production. Crude oil and condensate are distributed
through pipelines and trucks to gatherers, transportation companies and end
users. In order to manage its exposure to price risks, the Company from time to
time enters into hedging transactions, including crude oil and natural gas
futures swap contracts. In May 1995, NTI began marketing a portion of the
Company's oil as well as certain third party oil. The Company records all of
NTI's sales as gathering, marketing and processing revenues. All intercompany
sales and expenses have been eliminated.
Oil prices are affected by a variety of factors that are beyond the
control of the Company. The principal factors influencing the prices received
by producers of domestic crude oil continue to be the pricing and production of
the members of the Organization of Petroleum Exporting Countries. The Company's
average per barrel oil price increased from $14.90 in 1994 to $16.78 in 1995.
The Company's average oil prices for 1995 reflected an additional amount per
barrel of $.16, from hedging oil production. The Company did not hedge any of
its oil production during 1994.
Substantial competition in the natural gas marketplace continued in
1995. Gas prices, which were once determined largely by governmental
regulations, are now being influenced to a greater extent by the marketplace.
The Company's average gas price decreased from $1.97 per Mcf in 1994 to $1.72
per Mcf in 1995. The Company's average gas price in 1995 reflected a reduction
of $.004 per Mcf, from hedging gas production. During 1994, all gas hedging
activity related to sales by the Company's marketing subsidiary, NGM, which
hedged an average of approximately 32,000 Million British Thermal Units
(MMBTU's) of gas per day at prices ranging from $.01 per MMBTU above index to
$.58 per MMBTU above index. Hedging gains and losses for 1994 are included in
gathering, marketing and processing revenues.
The largest single customer for the Company's oil in 1995 purchased
approximately 16 percent of its oil production, and the five largest purchasers
accounted for approximately 49 percent of total oil production. The largest
single customer for the Company's gas in 1995 purchased approximately 4 percent
of its gas production, and the five largest purchasers accounted for
approximately 17 percent of total gas production. The Company does not believe
that the loss by the Company of a major oil or gas customer would have a
material adverse effect on the Company.
REGULATION AND RISKS
GENERAL. Exploration for and production and sale of oil and gas are
extensively regulated at the national, state and local levels. Oil and gas
development and production activities are subject to various state laws and
regulations (and orders of regulatory bodies pursuant thereto) governing a wide
variety of matters, including allowable rates of production, marketing, pricing,
prevention of waste and pollution, and protection of the environment. Laws
affecting the oil and gas industry are under constant review for amendment or
expansion and frequently increase the regulatory burden on companies. Numerous
governmental departments and agencies are authorized by statute to issue rules
and regulations binding on the oil and gas industry. Many of these governmental
bodies have issued rules and regulations that are often difficult and costly to
comply with, and that carry substantial penalties for failure to comply. These
laws, regulations and orders may restrict the rate of oil and gas production
below the rate that would otherwise exist in the absence of such laws,
regulations and orders. The regulatory burden on the oil and gas industry
increases its costs of doing business and consequently affects its
profitability.
NATURAL GAS. The natural gas industry has been regulated under the
Natural Gas Act and the Natural Gas Policy Act of 1978 (the "NGPA"). Under the
Natural Gas Wellhead Decontrol Act of 1989, price ceilings have been eliminated
over a transition period which ended on January 1, 1993.
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CERTAIN RISKS. In Samedan's exploration operations, losses may occur
before any accumulation of oil or gas is found. If oil or gas is discovered, no
assurance can be given that sufficient reserves will be developed to enable
Samedan to recover the costs incurred in obtaining the reserves or that reserves
will be developed at a rate sufficient to replace reserves currently being
produced and sold. Samedan's international operations are also subject to
certain political, economic and other uncertainties including, among others,
risks of war, expropriation, renegotiation or modification of existing
contracts, taxation policies, foreign exchange restrictions, international
monetary fluctuations and other hazards arising out of foreign governmental
sovereignty over areas in which Samedan conducts operations.
ENVIRONMENTAL MATTERS. As a developer, owner and operator of oil and
gas properties, Samedan is subject to various federal, state, local and foreign
country laws and regulations relating to the discharge of materials into, and
the protection of, the environment. The release or discharge of oil from
Samedan's domestic onshore or offshore facilities could subject Samedan to
liability under federal laws and regulations, including the Oil Pollution Act of
1990, the Outer Continental Shelf Lands Act and the Clean Water Act, for
pollution cleanup costs, damage to the environment, civil or criminal penalties,
and orders or injunctions requiring the suspension or cessation of operations in
affected areas. The liability under these laws for a substantial release or
discharge of oil, subject to certain specified limitations on liability, may be
extraordinarily large. If any oil pollution was caused by willful misconduct,
willful negligence or gross negligence, or was caused primarily by a violation
of federal regulations, such limitations on liability may not apply. Certain of
Samedan's facilities are subject to regulations of the United States
Environmental Protection Agency, including regulations that require the
preparation and implementation of spill prevention control and countermeasure
plans relating to the possible discharge of oil into navigable water.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as "Superfund", imposes liability on certain classes
of persons that contributed to the release or threatened release of a hazardous
substance into the environment or that own or operate facilities or vessels onto
or into which hazardous substances are disposed. The Resource Conservation and
Recovery Act ("RCRA") and regulations promulgated thereunder regulate hazardous
waste, including its treatment, storage and disposal. CERCLA currently exempts
crude oil, and RCRA currently exempts certain oil and gas exploration and
production drilling materials, such as drilling fluids and produced waters, from
the definitions of hazardous substances and hazardous wastes. Samedan's
operations, however, may involve the use or handling of other materials that may
be classified as hazardous substances or hazardous wastes, and therefore, these
statutes and regulations promulgated under them would apply to Samedan's
generation, handling and disposal of these materials. In addition, there can be
no assurance that such exemptions will be preserved in future amendments of such
acts, if any, or that more stringent laws and regulations protecting the
environment will not be adopted.
Certain of Samedan's facilities may also be subject to other federal
environmental laws and regulations, including the Clean Air Act with respect to
emissions of air pollutants. Certain state or local laws or regulations may
impose liabilities in addition to or restrictions more stringent than those
described herein. The environmental laws, rules and regulations of foreign
countries are generally less stringent than those of the United States, and
therefore, the requirements of such jurisdictions do not generally impose an
additional compliance burden on Samedan.
Samedan has made and will continue to make expenditures in its efforts
to comply with environmental requirements. The Company does not believe that it
has to date expended material amounts in connection with such activities or that
compliance with such requirements will have a material adverse effect upon the
capital expenditures, earnings or competitive position of the Company. Although
such requirements do have a substantial impact upon the energy industry,
generally they do not appear to affect the Company any differently or to any
greater or lesser extent than other companies in the industry.
INSURANCE. Samedan believes that it has such insurance coverages as
are customary in the industry and that it is adequately protected by public
liability and physical damage insurance.
COMPETITION
The oil and gas industry is highly competitive. Since many
companies and individuals are engaged in exploring for oil and gas and
acquiring oil and gas properties, a high degree of competition for desirable
exploratory
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and producing properties exists. A number of the companies with which
Samedan competes are larger and have greater financial resources than Samedan.
The availability of a ready market for Samedan's oil and gas
production depends on numerous factors beyond its control, including the level
of consumer demand, the extent of worldwide oil and gas production, the costs
and availability of alternative fuels, the costs of and proximity of pipelines
and other transportation facilities, regulation by state and federal authorities
and the costs of complying with applicable environmental regulations.
EMPLOYEES
The total number of employees of the Company increased from 521 at
December 31, 1994 to 550 at December 31, 1995.
ITEM 2. PROPERTIES.
OFFICES
The principal executive office of the Company is located at 110 West
Broadway, Ardmore, Oklahoma 73401. The principal executive office of Samedan is
in Ardmore, Oklahoma, and Samedan also maintains division offices in Oklahoma
City, Houston, Denver and Calgary, Canada. Samedan maintains three separate
offices in Houston for its international, offshore and onshore oil and gas
operations. Samedan maintains an office in Tunis, Tunisia, from which it
operates its various concessions and producing properties in Tunisia. The
principal executive office of NGM is located in Houston.
OIL AND GAS
The estimated proved and proved developed oil and gas reserves of
Samedan, as of December 31, 1995, 1994 and 1993 and the standardized measure of
discounted future net cash flows attributable thereto at December 31, 1995, 1994
and 1993 are included in Note 10 of Notes to Consolidated Financial Statements
appearing on pages 34 through 37 of the Registrant's 1995 annual report to
shareholders, which Note is incorporated herein by reference ("Note 10").
Note 10 also includes Samedan's net production (including royalty and
working interest production) of oil and natural gas for the three years ended
December 31, 1995. Royalty production of both oil and gas (stated in oil barrel
equivalents) is included in the "Crude Oil & Condensate" presentation in
Note 10. Samedan has no oil or gas applicable to long-term supply or similar
agreements with foreign governments or authorities in which Samedan acts as
producer.
Since January 1, 1995, no oil or gas reserve information has been
filed with, or included in any report to, any federal authority or agency other
than the Securities and Exchange Commission and the Energy Information
Administration (the "EIA"). Samedan files Form 23, including reserve and other
information, with the EIA.
The following table sets forth for each of the last three years the
average sales price (including transfers) per unit of oil produced and per unit
of natural gas produced, and the average production (lifting) cost per unit of
production.
7
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1995 1994 1993
------ ------ ------
<S> <C> <C> <C>
Average sales price per bbl of oil (1):
United States . . . . . . . . . $16.80 $14.76 $16.05
Canada. . . . . . . . . . . . . $15.59 $13.72 $15.13
Other international . . . . . . $17.22 $16.75 $15.32
Combined. . . . . . . . . . $16.78(2) $14.90 $15.91(2)
Average sales price per Mcf of natural gas (1):
United States . . . . . . . . . $ 1.75 $ 1.99 $ 2.15
Canada. . . . . . . . . . . . . $ 1.02 $ 1.47 $ 1.22
Combined. . . . . . . . . . $ 1.72(3) $ 1.97 $ 2.10(3)
Average production (lifting) cost per unit of
oil and natural gas production, excluding
depreciation (per bbl)(4):
United States . . . . . . . . . $ 4.17 $ 3.64 $ 4.26
Canada. . . . . . . . . . . . . $ 6.39 $ 5.17 $ 6.33
Other international . . . . . . $ 3.60 $ 3.89 $ 6.40
Combined . . . . . . . . . $ 4.21 $ 3.71 $ 4.45
</TABLE>
- -----------
(1) Net production amounts used in this calculation include royalties.
(2) Includes per barrel $.16 in 1995 and $0.02 in 1993, from hedging.
(3) Reflects a reduction per Mcf of $.004 in 1995 and $0.048 in 1993, from
hedging.
(4) Gas production is converted to oil barrel equivalents based on the
average sales prices per barrel of oil and per Mcf of gas. Net
production amounts used in the calculation of average sales prices for
purposes of computing the conversion ratio excludes royalties.
Conversion ratios for 1995, 1994 and 1993 are set forth below:
United States Canada
------------- ------
1995 9.61 to 1 15.32 to 1
1994 7.44 to 1 9.42 to 1
1993 7.46 to 1 12.45 to 1
8
<PAGE>
The number of productive oil and gas wells in which Samedan had interests
and the developed acreage held as of December 31, 1995, were as follows:
<TABLE>
<CAPTION>
Productive Wells(1)(2) Developed Acreage(3)(4)
--------------------------------- -----------------------
Oil Gas
--------------- ---------------
Location Gross Net Gross Net Gross Acres Net Acres
- -------- ------- ----- ------- ----- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
United States
(onshore). . . . . . 3,554.5 796.0 1,346.5 765.6 584,096 360,001
Canada . . . . . . . . 119.0 39.3 72.0 18.2 127,776 41,857
United States
(offshore) . . . . . 256.5 110.9 432.5 166.0 738,474 292,991
Other International. . 7.0 2.6 2.0 0.7 367,762 129,478
------- ----- ------- ----- --------- -------
Total. . . . . . . . . 3,937.0 948.8 1,853.0 950.5 1,818,108 824,327
------- ----- ------- ----- --------- -------
------- ----- ------- ----- --------- -------
</TABLE>
- -----------
(1) Productive wells are producing wells and wells capable of production. A
gross well is a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is
owned. A net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The number of net
wells is the sum of the fractional working interests owned in gross wells
expressed as whole numbers and fractions thereof.
(2) One or more completions in the same bore hole is counted as one well.
Included in the table and counted as one gross well each are 28.0 oil
wells (18.2 net) and 46.0 gas wells (19.4 net) that are multiple
completions. Also included in the table are 824.0 gross oil wells (131.8
net) and 81.0 gross gas wells (42.7 net) that were not producing at
December 31, 1995 because such wells were awaiting additional action or
pipeline connections.
(3) Developed acreage is acreage spaced or assignable to productive wells.
(4) A gross acre is an acre in which a working interest is owned. A net acre
is deemed to exist when the sum of fractional ownership working interests
in gross acres equals one. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
9
<PAGE>
The undeveloped acreage (including both leases and concessions) that
Samedan held as of December 31, 1995, is as follows:
<TABLE>
<CAPTION>
Undeveloped Acreage (1)(2)
--------------- ---------
Location Gross Acres Net Acres
- -------- --------------- ---------
<S> <C> <C>
United States Onshore
California. . . . . . . . . . . . . . . 25,622 12,556
Colorado. . . . . . . . . . . . . . . . 38,930 30,059
Mississippi . . . . . . . . . . . . . . 5,171 3,326
Montana . . . . . . . . . . . . . . . . 34,278 14,223
New Mexico. . . . . . . . . . . . . . . 11,700 7,593
North Dakota. . . . . . . . . . . . . . 29,132 13,023
Oklahoma. . . . . . . . . . . . . . . . 22,751 11,359
Texas . . . . . . . . . . . . . . . . . 60,408 23,949
Utah. . . . . . . . . . . . . . . . . . 2,507 1,841
Wyoming . . . . . . . . . . . . . . . . 43,879 10,634
Others. . . . . . . . . . . . . . . . . 10,492 4,706
--------- ---------
Total United States Onshore . . . . 284,870 133,269
--------- ---------
United States Offshore (Federal Waters)
Alabama . . . . . . . . . . . . . . . . 166,195 63,670
California. . . . . . . . . . . . . . . 79,678 8,625
Louisiana . . . . . . . . . . . . . . . 163,468 85,663
Mississippi . . . . . . . . . . . . . . 28,800 24,960
Texas . . . . . . . . . . . . . . . . . 71,723 62,122
--------- ---------
Total United States Offshore
(Federal Waters). . . . . . . 509,864 245,040
--------- ---------
International
Canada. . . . . . . . . . . . . . . . . 333,959 177,916
Tunisia . . . . . . . . . . . . . . . . 1,639,450 786,079
--------- ---------
Total International . . . . . . . . 1,973,409 963,995
--------- ---------
Total . . . . . . . . . . . . . . . 2,768,143 1,342,304
--------- ---------
--------- ---------
</TABLE>
(1) Undeveloped acreage is considered to be those lease acres on which wells
have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas regardless of whether
or not such acreage contains proved reserves. Included within undeveloped
acreage are those lease acres (held by production under the terms of a
lease) that are not within the spacing unit containing, or acreage
assigned to, the productive well so holding such lease.
(2) A gross acre is an acre in which a working interest is owned. A net acre
is deemed to exist when the sum of fractional ownership working interests
in gross acres equals one. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
The following table sets forth for each of the last three years the number
of net exploratory and development wells drilled by or on behalf of Samedan.
An exploratory well is a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known
reservoir. A development well, for purposes of the following table and as
defined in the rules and regulations of the Securities and Exchange
Commission, is a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
The number of wells drilled refers to the number of wells completed at any
time during the respective year, regardless of when drilling was initiated;
and "completion" refers to the installation of permanent equipment for the
production of oil or gas, or, in the case of a dry hole, to the reporting of
abandonment to the appropriate agency.
10
<PAGE>
<TABLE>
<CAPTION>
Net Exploratory Wells
-------------------------------------------------------------
Productive (1) Dry (2)
----------------------------- -------------------------------
Year Ended Other Other
December 31, U.S. Canada International U.S. Canada International
- ----------- ---- ------ ------------- ----- ------ -------------
<S> <C> <C> <C> <C> <C> <C>
1993 . . . . . 5.58 1.10 -- 10.67 5.29 1.30
1994 . . . . . 8.06 3.75 -- 16.45 6.59 .40
1995 . . . . .12.44 .80 -- 14.42 3.72 1.00
</TABLE>
<TABLE>
<CAPTION>
Net Development Wells
-------------------------------------------------------------
Productive (1) Dry (2)
----------------------------- -------------------------------
Year Ended Other Other
December 31, U.S. Canada International U.S. Canada International
- ----------- ---- ------ ------------- ----- ------ -------------
<S> <C> <C> <C> <C> <C> <C>
1993 . . . . .33.07 2.62 -- 3.06 1.37 --
1994 . . . . .99.91 3.08 -- 13.37 .14 --
1995 . . . . 107.09 5.50 -- 20.49 .14 --
</TABLE>
- -------------
(1) A productive well is an exploratory or a development well that is not a
dry hole.
(2) A dry hole is an exploratory or development well found to be incapable of
producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
Samedan spent approximately $43.7 million in 1995 on the purchase of
producing oil and gas properties. See Item 1. "Business -- Oil and Gas
- --Acquisitions" hereof for a discussion of acquisitions in 1995.
Approximately $6.1 million and $418.5 million, respectively, were spent on
such purchases in 1994 and 1993.
At February 27, 1996, Samedan was drilling 5 gross (1.9 net) exploratory
wells, and 14 gross (8.7 net) development wells. These wells are located
onshore in the United States in Colorado, Louisiana, North Dakota, Oklahoma,
Texas, Wyoming and offshore Gulf of Mexico. These wells have objectives
ranging from approximately 2,500 to 15,500 feet. The estimated drilling cost
to Samedan of these wells is approximately $9,064,000 if all are dry and
approximately $20,975,000 if all are completed as producing wells.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings, other than ordinary
routine litigation incidental to the business of the Registrant and its
subsidiaries, to which the Registrant or any of its subsidiaries is a party
or of which any of their property is the subject.
On December 20, 1995 the Registrant announced that Samedan had received
$48.9 million from the settlement of its bankruptcy claim against Columbia
Gas Transmission Corporation ("Columbia Transmission"), a unit of Columbia
Gas Systems, Inc. ("Columbia Systems"). The payment was received pursuant to
the terms of a comprehensive producer settlement agreement which was entered
into with Columbia Transmission and Columbia Systems in connection with their
plans of reorganization filed in the Bankruptcy Court on April 17, 1995. The
settlement agreement also gives Samedan a contingent right to receive
approximately $2.5 million upon the resolution of certain other contested
producer claims.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
11
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
The following tabulation sets forth certain information, as of March 11,
1996, with respect to the executive officers of the Registrant.
Name Age Position
---- --- --------
Robert Kelley (1) 50 Chairman of the Board, President,
Chief Executive Officer, Director
George L. DeMare, Jr. (2) 50 Vice President and Operating
Committee Member of Samedan
William D. Dickson (3) 47 Vice President-Finance and Treasurer
of the Registrant and Operating
Committee Member of Samedan
Dan O. Dinges (4) 42 Vice President and Operating
Committee Member of Samedan
W. A. Poillion (5) 46 Vice President and Operating
Committee Member of Samedan
Orville Walraven (6) 51 Corporate Secretary of the
Registrant and Vice President
and Operating Committee Member of
Samedan
James C. Woodson (7) 53 Vice President and Operating
Committee Member of Samedan
_____________________
(1) Robert Kelley has served as President and Chief Executive Officer of
the Registrant since August 1, 1986, and as Chairman of the Board
since October 27, 1992. Prior to serving as President, he served as
Executive Vice President of the Registrant from January 1986. Mr.
Kelley became a director of the Registrant in July 1986. He currently
also serves as President and Chief Executive Officer of Samedan. He
became President of Samedan in 1984 after serving previously as
Executive Vice President and Vice President-Finance.
(2) George L. DeMare, Jr. has served as Vice President and Onshore
Division Manager of Samedan since January 1989. Mr. DeMare has been a
member of the Operating Committee of Samedan since January 31, 1995.
(3) William D. Dickson was elected Vice President-Finance and Treasurer of
the Registrant in October 1985. He has served as Vice President-
Finance, Treasurer and Assistant Secretary of Samedan since 1984 and
as a member of the Operating Committee of Samedan since February 9,
1994.
(4) Dan O. Dinges has served as Vice President and Division General
Manager, Offshore Division of Samedan since January 1989. Mr. Dinges
has been a member of the Operating Committee of Samedan since
January 31, 1995.
(5) W. A. Poillion has served as Vice President - Production and Drilling
and a member of the Operating Committee of Samedan since November 1,
1990. Prior thereto, he served as Manager of Offshore Production and
Drilling for Samedan from March 1, 1985 to October 31, 1990.
(6) Orville Walraven has served as Corporate Secretary of the Registrant
since January 1, 1989. He has also served as Vice President - Land of
Samedan and as a member of the Operating Committee of Samedan since
January 1, 1989.
(7) James C. Woodson has served as Vice President - Exploration of Samedan
since September 1, 1983. Mr. Woodson has been a member of the
Operating Committee of Samedan since August 1, 1986.
12
<PAGE>
The terms of office for the officers of the Registrant continue
until their successors are chosen and qualified. No officer or executive
officer of the Registrant has an employment agreement with the Registrant or
any of its subsidiaries. There are no family relationships between any of
the Registrant's officers.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Registrant's common stock is listed and traded on the New York
Stock Exchange under the symbol "NBL". The table captioned "Dividends and
Stock Prices by Quarters" appearing on page 40 of the Registrant's 1995
annual report to stockholders contains certain information with respect to
sales prices of the common stock and cash dividends declared by the
Registrant on the common stock, and such table is incorporated herein by
reference.
At December 31, 1995, there were 1,790 stockholders of record of
the Registrant.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data of the Registrant is set forth on page 21
of the Registrant's 1995 annual report to stockholders and is incorporated
herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
Management's discussion and analysis of financial condition and
results of operations is set forth on pages 15 through 20 of the Registrant's
1995 annual report to stockholders and is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The consolidated financial statements, appearing on pages 22
through 32, together with the report thereon of Arthur Andersen LLP dated
January 26, 1996 appearing on page 33, and the unaudited information,
appearing on pages 34 through 37, of the Registrant's 1995 annual report to
stockholders are incorporated herein by reference. With the exception of the
aforementioned information and the information expressly incorporated into
Items 2, 5, 6 and 7 hereof, the 1995 annual report to stockholders is not to
be deemed to be filed as part of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The section entitled "Election of Directors" appearing on pages 3
and 4 of the Registrant's proxy statement for the 1996 annual meeting of
stockholders sets forth certain information with respect to the directors of
the Registrant and is incorporated herein by reference. Certain information
with respect to the executive officers of the Registrant is set forth under
the caption "Executive Officers of the Registrant" in Part I of this report.
The section entitled "Certain Transactions" appearing on page 23 of
the Registrant's proxy statement for the 1996 annual meeting of stockholders
sets forth certain information with respect to compliance with Section 16(a)
of the Exchange Act and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The section entitled "Executive Compensation" appearing on pages 7
through 14 of the Registrant's proxy statement for the 1996 annual meeting of
stockholders sets forth certain information with respect to the compensation
of management of the Registrant, and, except for the report of the
compensation and benefits committee of the Board of Directors (pages 7
through 10) and the information therein under "Performance Graph" (page 14),
is incorporated herein by reference.
13
<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The sections entitled "Security Ownership of Certain Beneficial
Owners" and "Security Ownership of Directors and Executive Officers"
appearing on pages 2 through 3 and 6, respectively, of the Registrant's proxy
statement for the 1996 annual meeting of stockholders set forth certain
information with respect to the ownership of the Registrant's common stock,
and are incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Not applicable.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
<TABLE>
<CAPTION>
Page In 1995
Annual Report
to Stockholders
(Incorporated
by Reference)
----------------
<S> <C>
(1) Financial Statements:
Consolidated Balance Sheet at December 31, 1995 and 1994 . . 22
Consolidated Statement of Operations for the three
years ended December 31, 1995 . . . . . . . . . . . . . . . 23
Consolidated Statement of Cash Flows for the three
years ended December 31, 1995 . . . . . . . . . . . . . . . 24
Consolidated Statement of Shareholders' Equity for the
three years ended December 31, 1995. . . . . . . . . . . . 25
Notes to Consolidated Financial Statements . . . . . . . . . 26
Report of Independent Public Accountants . . . . . . . . . . 33
Supplemental Oil and Gas Information (Unaudited) and
Interim Financial Information (Unaudited) . . . . . . . . . 34
(2) Financial Statement Schedules:
</TABLE>
All schedules are omitted because they are not applicable
or the required information is shown in the financial
statements or notes thereto.
Financial statements of two 50 percent or less owned entities
accounted for by the equity method have been omitted because, in the
aggregate, the proportionate share of their profit before income taxes and
total assets are less than 20 percent of the respective consolidated amounts,
and investments in such entities are less than 20 percent of consolidated
total assets of the Registrant.
(3) Exhibits:
The exhibits required to be filed by this Item 14 are set
forth in the Index to Exhibits accompanying this report.
(b) No report on Form 8-K was filed by the Registrant during
the quarter ended December 31, 1995.
14
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
NOBLE AFFILIATES, INC.
Date: March 25, 1996 By: /s/ WILLIAM D. DICKSON,
---------------------------------------
William D. Dickson,
Vice President-Finance and Treasurer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Signature Capacity in which signed Date
- --------- ------------------------ ----
/s/ ROBERT KELLEY Chairman of the Board, President, March 25, 1996
- ------------------------ Chief Executive Officer and
Robert Kelley Director (Principal Executive
Officer)
/s/ WILLIAM D. DICKSON Vice President-Finance and March 25, 1996
- ------------------------ Treasurer (Principal Financial
William D. Dickson and Accounting Officer)
/s/ ALAN A. BAKER Director March 25, 1996
- ------------------------
Alan A. Baker
/s/ ROY BUTLER Director March 25, 1996
- ------------------------
Roy Butler
/s/ MICHAEL A. CAWLEY Director March 25, 1996
- ------------------------
Michael A. Cawley
/s/ EDWARD F. COX Director March 25, 1996
- ------------------------
Edward F. Cox
/s/ JAMES C. DAY Director March 25, 1996
- ------------------------
James C. Day
/s/ HAROLD F. KLEINMAN Director March 25, 1996
- ------------------------
Harold F. Kleinman
/s/ GEORGE J. MCLEOD Director March 25, 1996
- ------------------------
George J. McLeod
/s/ GUY W. NICHOLS Director March 25, 1996
- ------------------------
Guy W. Nichols
/s/ JOHN F. SNODGRASS Director March 25, 1996
- ------------------------
John F. Snodgrass
S-1
<PAGE>
INDEX TO EXHIBITS
Exhibit
Number Exhibit
- ------- -------
3.1 Certificate of Incorporation, as amended, of the Registrant as
currently in effect (filed as Exhibit 3.2 to the Registrant's
annual report on Form 10-K for the fiscal year ended December
31, 1987 and incorporated herein by reference).
3.2 Composite copy of Bylaws as currently in effect (filed as
Exhibit 3.2 to the Registrant's annual report on Form 10-K for
the year ended December 31, 1992 and incorporated herein by
reference).
4.1 Indenture dated as of June 6, 1989, between the Registrant and
First RepublicBank Dallas, National Association, Trustee,
including form of the Registrant's 10 1/8% Notes Due June 1,
1997 (filed as Exhibit 4.1 to the Registrant's Registration
Statement on Form S-3 (Registration No. 33-14111) and
incorporated herein by reference).
4.2 Indenture dated as of October 14, 1993 between the Registrant
and U.S. Trust Company of Texas, N.A., as Trustee, relating to
the Registrant's 7 1/4% Notes Due 2023, including form of the
Registrant's 7 1/4% Note Due 2023 (filed as Exhibit 4.1 to the
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1993 and incorporated herein by reference).
4.3 Indenture dated as of October 14, 1993 entered into between the
Registrant and United States Trust Company of New York, as
Trustee, relating to the Registrant's 4 1/4% Convertible
Subordinated Notes Due 2003, including form of the
Registrant's 4 1/4% Convertible Subordinated Note Due 2003
(filed as Exhibit 4.2 to the Registrant's quarterly report on
Form 10-Q for the quarter ended September 30, 1993 and
incorporated herein by reference).
10.1* Samedan Oil Corporation Bonus Plan revised January 1, 1992
(filed as Exhibit 10.1 to the Registrant's annual report on
Form 10-K for the year ended December 31, 1992 and
incorporated herein by reference).
10.2* Noble Affiliates Thrift and Profit Sharing Plan, as amended and
restated effective as of January 1, 1994 (filed as Exhibit
10.2 to the Registrant's annual report on Form 10-K for the
fiscal year ended December 31, 1994 and incorporated herein by
reference).
10.3* Noble Affiliates Thrift and Profit Sharing Trust, amended and
restated effective as of January 1, 1988 (filed as Exhibit
10.3 to the Registrant's annual report on Form 10-K for the
fiscal year ended December 31, 1987 and incorporated herein by
reference).
10.4* Amendment No. 9 to the Noble Affiliates Thrift and Profit
Sharing Plan, as amended and restated, effective as of
September 1, 1988 (filed as Exhibit 10.4 to the Registrant's
annual report on Form 10-K for the fiscal year ended December
31, 1994 and incorporated herein by reference).
10.5* Restoration of Retirement Income Plan for certain participants
in the Noble Affiliates Retirement Plan dated September 21,
1994, effective as of May 19, 1994 (filed as Exhibit 10.5 to
the Registrant's annual report on Form 10-K for the fiscal
year ended December 31, 1994 and incorporated herein by
reference).
10.6* Noble Affiliates Thrift Restoration Plan dated May 19, 1994
(filed as Exhibit 10.6 to the Registrant's annual report on
Form 10-K for the fiscal year ended December 31, 1994 and
incorporated herein by reference).
10.7* Noble Affiliates Restoration Trust dated September 21, 1994,
effective as of October 1, 1994 (filed as Exhibit 10.7 to the
Registrant's annual report on Form 10-K for the fiscal year
ended December 31, 1994 and incorporated herein by reference).
E-1
<PAGE>
10.8* Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock
Plan, as amended and restated, dated November 2, 1992 (filed
as Exhibit 4.1 to registration statement on Form S-8
(Registration No. 33-54084) and incorporated herein by
reference).
10.9* 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1
to registration statement on Form S-8 (Registration No.
2-81590) and incorporated herein by reference).
10.10* Amendment No. 1 to the 1982 Stock Option Plan of the Registrant
(filed as Exhibit 4.2 to registration statement on Form S-8
(Registration No. 2-81590) and incorporated herein by
reference).
10.11* Amendment No. 2 to the 1982 Stock Option Plan of the Registrant.
10.12* 1978 Non-Qualified Stock Option Plan of the Registrant (filed as
Exhibit 1.1 to registration statement on Form S-8
(Registration No. 2-64600) and incorporated herein by
reference).
10.13* 1978 Non-Qualified Stock Option Plan of the Registrant, as
amended July 27, 1978 (filed as Exhibit 1.2 to registration
statement on Form S-8 (Registration No. 2-64600) and
incorporated herein by reference).
10.14* Amendment No. 2 to 1978 Non-Qualified Stock Option Plan of the
Registrant (filed as Exhibit 10.20 to the Registrant's annual
report on Form 10-K for the year ended December 31, 1993 and
incorporated herein by reference).
10.15* Amendment No. 3 to 1978 Non-Qualified Stock Option Plan of the
Registrant.
10.16* 1988 Nonqualified Stock Option Plan for Non-Employee Directors
of the Registrant (filed as Exhibit 10.3 to the Registrant's
annual report on Form 10-K for the fiscal year ended December
31, 1988 and incorporated herein by reference).
10.17* Amendment No. 1 to 1988 Nonqualified Stock Option Plan for
Non-Employee Directors of the Registrant dated as of July 28,
1992 (filed as Exhibit 10.13 to the Registrant's annual report
on Form 10-K for the year ended December 31, 1992 and
incorporated herein by reference).
10.18* Form of Indemnity Agreement entered into between the Registrant
and each of the Registrant's directors and bylaw officers.
10.19 Guaranty of the Registrant dated October 28, 1982, guaranteeing
certain obligations of Samedan (filed as Exhibit 10.12 to the
Registrant's annual report on Form 10-K for the year ended
December 31, 1993 and incorporated herein by reference).
10.20 Credit Agreement dated as of March 2, 1988, among the Registrant,
Bankers Trust Registrant, as Agent, and the banking
institutions listed in Annex I thereto (filed as Exhibit 10.25
to the Registrant's annual report on Form 10-K for the year
ended December 31, 1987 and incorporated herein by reference).
10.21 First Amendment to Credit Agreement dated as of December 22,
1989, among the Registrant, Bankers Trust Company, as Agent,
and the banking institutions party to the Credit Agreement
(filed as Exhibit 10.16 to the Registrant's annual report on
Form 10-K for the year ended December 31, 1991 and
incorporated herein by reference).
E-2
<PAGE>
10.22 Second Amendment to Credit Agreement dated as of October 31,
1991, among the Registrant, Bankers Trust Company, as Agent,
and the banking institutions party to the Credit Agreement
(filed as Exhibit 10.17 to the Registrant's annual report on
Form 10-K for the year ended December 31, 1991 and
incorporated herein by reference).
10.23 Third Amendment to Credit Agreement, among the Registrant,
Bankers Trust Company, as Agent, and the banking institutions
party to the Credit Agreement dated as of October 30, 1992
(filed as Exhibit 10.24 to the Registrant's annual report on
Form 10-K for the year ended December 31, 1992 and
incorporated herein by reference).
10.24 Fourth Amendment to Credit Agreement dated as of September 30,
1993 among the Registrant, Bankers Trust Company, as Agent,
and the financial institutions listed on the signature pages
thereto (filed as Exhibit 2.6 to the Registrant's Registration
Statement on Form S-3 (No. 33-69248) and incorporated herein
by reference).
10.25 Agreement dated March 31, 1989, by and between Apache Corporation
and the Registrant (filed as Exhibit 2(a) to the Registrant's
current report on Form 8-K (Date of Report: May 16, 1989) and
incorporated herein by reference).
10.26 Consent regarding agreement dated April 30, 1989, by and between
Apache Corporation and the Registrant (filed as Exhibit 2(b)
to the Registrant's current report on Form 8-K (Date of
Report: May 16, 1989) and incorporated herein by reference).
10.27 Purchase and Sale Agreement dated as of June 24, 1993 by and
between Freeport-McMoRan Oil & Gas Company Division of
Freeport-McMoRan Inc., individually and as Managing General
Partner of FM Properties Operating Co., and Samedan Oil
Corporation (filed as Exhibit 2 to the Registrant's Current
Report on Form 8-K dated July 29, 1993 and incorporated herein
by reference).
10.28 Purchase and Sale Agreement dated as of September 16, 1993 by and
between FM Properties Operating Co. and Samedan Oil
Corporation (filed as Exhibit 2.2 to the Registrant's
Registration Statement on Form S-3 (No. 33-69248) and
incorporated herein by reference).
10.29 Purchase and Sale Agreement (Installment Sale) dated as of
September 16, 1993 by and between FM Properties Operating Co.
and Samedan Oil Corporation (filed as Exhibit 2.3 to the
Registrant's Registration Statement on Form S-3 (No. 33-69248)
and incorporated herein by reference).
10.30 Promissory Note dated October 1, 1993 of Samedan Oil Corporation
in the principal amount of $95.6 million payable to FM
Properties Operating Co. in connection with the agreement
filed as Exhibit 10.32 hereto (filed as Exhibit 2.4 to the
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1993 and incorporated herein by reference).
10.31 Letter agreement dated September 16, 1993 between FM Properties
Operating Co. and Samedan Oil Corporation relating to the
agreements filed as Exhibits 10.31 and 10.32 hereto (filed as
Exhibit 2.5 to the Registrant's Registration Statement on Form
S-3 (No. 33-69248) and incorporated herein by reference).
E-3
<PAGE>
13 The following information appearing on the following pages of the
Registrant's 1995 annual report to shareholders: (i)
management's discussion and analysis of financial condition
and results of operations, pages 15 through 20; (ii) selected
financial data, page 21; (iii) the consolidated financial
statements, together with the report thereon of Arthur
Andersen LLP dated January 26, 1996, pages 22 through 33, and the
unaudited information, pages 34 through 37; and (iv) the table
captioned "Dividends and Stock Prices by Quarters," page 40.
21 Subsidiaries.
23 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
- --------------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit hereto.
E-4
<PAGE>
Exhibit 10.11
AMENDMENT No. 2
TO THE
1982 STOCK OPTION PLAN
OF NOBLE AFFILIATES, INC.
WHEREAS, Noble Affiliates, Inc. (the "Company") has proposed the
distribution of the common stock of Noble Drilling Corporation ("Noble
Drilling") on a pro rata basis to holders of the common stock of the Company
(the "Distribution"), which proposal is described in detail in the Company's
proxy statement dated March 25, 1985 (terms used and not otherwise defined
herein are used herein with the meanings assigned to them in such proxy
statement); and
WHEREAS, the proposed Distribution may require an adjustment in the terms
of outstanding stock options granted under the 1982 Stock Option Plan of Noble
Affiliates, Inc. (the "1982 Plan") to compensate the option holder for the loss
of his right to indirectly purchase part of Noble Drilling and the possible loss
of a portion of the market value of the Company's common stock as a result of
the Distribution; and
WHEREAS, on March 22, 1985, the Board of Directors of the Company adopted a
resolution providing for the amendment (the "Amendment") of the 1982 Plan in
connection with the proposed Distribution, and on April 23, 1985, the
shareholders of the Company approved the Amendment; and
WHEREAS, any increase in the number of authorized shares under the 1982
Plan as a result of the Amendment cannot be determined until after the
Distribution Record Date and Company Adjustment Date;
NOW, THEREFORE, the 1982 Plan is hereby amended in the following respect
only:
The first sentence of Section 3 of the 1982 Plan is hereby amended by
restatement in its entirety to read as follows:
"Options may be granted by the Company from time
to time under the Plan to purchase an aggregate of
2,089,349 shares of the authorized but unissued
Common Stock."
PROVIDED, upon determination that the Amendment effects an increase in the
authorized shares under the 1982 Plan, the Secretary of the Company is
authorized and directed to fill in the blank in the first sentence of Section 3
of the 1982 Plan with the aggregate number of shares then authorized by the 1982
Plan, it being intended that until such time (and thereafter if no increase is
necessary), the authorized shares under the 1982
<PAGE>
Plan shall be 2,000,000.
IN WITNESS WHEREOF, this Amendment has been executed as of the 30th day of
July, 1985.
NOBLE AFFILIATES, INC.
By, GEORGE J. McLEOD
George J. McLeod,
President and Chief Executive
Officer
-2-
<PAGE>
Exhibit 10.15
AMENDMENT NO. 3
TO THE
1978 NON-QUALIFIED STOCK OPTION PLAN
OF NOBLE AFFILIATES, INC.
WHEREAS, Noble Affiliates, Inc. (the "Company") has proposed the
distribution of the common stock of Noble Drilling Corporation ("Noble
Drilling") on a pro rata basis to holders of the common stock of the Company
(the "Distribution"), which proposal is described in detail in the Company's
proxy statement dated March 25, 1985 (terms used and not otherwise defined
herein are used herein with the meanings assigned to them in such proxy
statement); and
WHEREAS, the proposed Distribution may require an adjustment in the terms
of outstanding stock options granted under the Company's 1978 Non-Qualified
Stock Option Plan (the "1978 Plan") to compensate the option holder for the loss
of his right to indirectly purchase part of Noble Drilling and the possible loss
of a portion of the market value of the Company's common stock as a result of
the Distribution; and
WHEREAS, on March 22, 1985, the Board of Directors of the Company adopted a
resolution providing for the amendment (the "Amendment") of the 1978 Plan in
connection with the proposed Distribution, and on April 23, 1985, the
shareholders of the Company approved the Amendment; and
WHEREAS, any increase in the number of authorized shares under the 1978
Plan as a result of the Amendment cannot be determined until after the
Distribution Record Date and Company Adjustment Date;
NOW, THEREFORE, the 1978 Plan is hereby amended in the following respects
only:
FIRST: The first sentence of Section 3 of the 1978 Plan is
hereby amended by restatement in its entirety to read as follows:
"Options may be granted by the Company from time
to time under the Plan to purchase an aggregate of
2,186,397 shares of the authorized but unissued
Common Stock. "
SECOND: The second paragraph of Section 8 of the 1978 Plan is hereby
amended by restatement in its entirety to read as follows:
"Each option granted under the Plan shall be
exercisable from time to time over a period commencing
one year from the date of grant of the option and
<PAGE>
ending upon the termination of the option, provided
that the Committee may by the provisions of any option
limit the number of shares purchasable thereunder in
any period or periods of time during which the option
is exercisable and, provided further, that the
Committee, in its sole and absolute discretion, may
accelerate the exercise date of any outstanding Option
to any date subsequent to the date of grant."
PROVIDED, upon determination that the Amendment effects an increase in the
authorized shares under the 1978 Plan, the Secretary of the Company is
authorized and directed to fill in the blank in the first sentence of Section 3
of the 1978 Plan with the aggregate number of shares then authorized by the 1978
Plan, it being intended that until such time (and thereafter if no increase is
necessary), the authorized shares under the 1978 Plan shall be 2,160,000.
IN WITNESS WHEREOF, this Amendment has been executed as of the 30th day of
July, 1985.
NOBLE AFFILIATES, INC.
By, GEORG J. McLEOD
George J. McLeod,
President and Chief Executive
Officer
-2-
<PAGE>
EXHIBIT 10.18
INDEMNITY AGREEMENT
This Agreement made and entered into as of this _____ day of
_______________, _____, by and between NOBLE AFFILIATES, INC., a Delaware
corporation (the "Company"), and ___________________ ("Indemnitee"), who is
currently serving the Company in the capacity of a director and/or officer
thereof;
W I T N E S S E T H:
WHEREAS, the Company and Indemnitee recognize that the interpretation of
ambiguous statutes, regulations and court opinions and of the Certificate of
Incorporation and Bylaws of the Company, and the vagaries of public policy,
are too uncertain to provide the directors and officers of the Company with
adequate or reliable advance knowledge or guidance with respect to the legal
risks and potential liabilities to which they become personally exposed as a
result of performing their duties in good faith for the Company; and
WHEREAS, the Company and the Indemnitee are aware that highly
experienced and capable persons are often reluctant to serve as directors or
officers of a corporation unless they are protected to the fullest extent
permitted by law by comprehensive insurance or indemnification, especially
since the legal risks and potential liabilities, and the very threat thereof,
associated with lawsuits filed against the officers and directors of a
corporation, and the resultant substantial time, expense, harassment,
ridicule, abuse and anxiety spent and endured in defending against such
lawsuits, whether or not meritorious, bear no reasonable or logical
relationship to the amount of compensation received by the directors or
officers from the corporation; and
WHEREAS, Section 145 of the General Corporation Law of the State of
Delaware, which sets forth certain provisions relating to the mandatory and
permissive indemnification of, and advancement of expenses to, officers and
directors (among others) of a Delaware corporation by such corporation, is
specifically not exclusive of other rights to which those indemnified
thereunder may be entitled under any bylaw, agreement, vote of stockholders
or disinterested directors or otherwise, and, thus, does not by itself limit
the extent to which the Company may indemnify persons serving as its officers
and directors (among others); and
WHEREAS, after due consideration and investigation of the terms and
provisions of this Agreement and the various other options available to the
Company and the Indemnitee in lieu thereof, the board of directors of the
Company has determined that the following Agreement is not only reasonable
and prudent but necessary to promote and ensure the best interests of the
Company and its stockholders; and
WHEREAS, the Company desires to have Indemnitee serve or continue to
serve as an officer and/or director of the Company, free from undue concern
for unpredictable, inappropriate or unreasonable legal risks and personal
liabilities by reason of his acting in good faith in the performance of his
duty to the Company; and Indemnitee desires to serve, or to continue to serve
(provided that he is furnished the indemnity provided for hereinafter), in
either or both of such capacities;
1
<PAGE>
NOW, THEREFORE, in consideration of the premises and the mutual
agreements herein set forth and for other good and valuable consideration,
the receipt and sufficiency of which are hereby acknowledged, the Company and
Indemnitee, intending to be legally bound, do hereby agree as follows:
1. AGREEMENT TO SERVE. Indemnitee agrees to serve or continue to
serve as director and/or officer of the Company, at the will of the Company
or under separate contract, if such exists, for so long as he is duly elected
or appointed and qualified in accordance with the provisions of the Bylaws of
the Company or until such time as he tenders his resignation in writing.
2. DEFINITIONS. As used in this Agreement:
(a) The term "Proceeding" shall mean any action, suit or proceeding,
whether civil, criminal, administrative, arbitrative or investigative, any
appeal in such an action, suit or proceeding, and any inquiry or
investigation that could lead to such an action, suit or proceeding, except
one initiated by Indemnitee to enforce his rights under this Agreement.
(b) The term "Expenses" includes, without limitation, all reasonable
attorneys' fees, retainers, court costs, transcript costs, fees of experts,
witness fees, travel expenses, duplicating costs, printing and binding
costs, telephone charges, postage, delivery service fees and all other
disbursements or expenses of the types customarily incurred in connection
with prosecuting, defending, preparing to prosecute or defend,
investigating, or being or preparing to be a witness in a Proceeding.
(c) References to "other enterprise" shall include employee benefit
plans; references to "fines" shall include any (i) excise taxes assessed
with respect to any employee benefit plan and (ii) penalties; references to
"serving at the request of the Company" shall include any service as a
director, officer, employee or agent of the Company which imposes duties
on, or involves services by, such director, officer, employee or agent with
respect to an employee benefit plan, its participants or beneficiaries; and
a person who acts in good faith and in a manner he reasonably believes to
be in the interest of the participants and beneficiaries of an employee
benefit plan shall be deemed to have acted in a manner "not opposed to the
best interests of the Company" as referred to in this Agreement.
3. INDEMNITY IN THIRD PARTY PROCEEDINGS. The Company shall indemnify
Indemnitee in accordance with the provisions of this Section 3 if Indemnitee is
a party to or is threatened to be made a party to or otherwise involved in any
threatened, pending or completed Proceeding (other than a Proceeding by or in
the right of the Company to procure a judgment in its favor) by reason of the
fact that Indemnitee is or was a director and/or officer of the Company, or is
or was serving at the request of the Company as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against all Expenses, judgments, fines and amounts paid in
settlement actually and reasonably incurred by Indemnitee in connection with
such Proceeding, provided it is determined pursuant to Section 7 of this
Agreement or by the court having jurisdiction in the matter, that Indemnitee
acted in good
2
<PAGE>
faith and in a manner that he reasonably believed to be in or not opposed to
the best interests of the Company, and, with respect to any criminal
Proceeding, had no reasonable cause to believe his conduct was unlawful. The
termination of any Proceeding by judgment, order, settlement or conviction,
or upon a plea of NOLO CONTENDERE or its equivalent, shall not, of itself,
create a presumption that Indemnitee did not act in good faith and in a
manner that he reasonably believed to be in or not opposed to the best
interests of the Company, and, with respect to any criminal Proceeding, had
reasonable cause to believe that his conduct was unlawful.
4. INDEMNITY IN PROCEEDINGS BY OR IN THE RIGHT OF THE COMPANY. The
Company shall indemnify Indemnitee in accordance with the provisions of this
Section 4 if Indemnitee is a party to or is threatened to be made a party to
or otherwise involved in any threatened, pending or completed Proceeding by
or in the right of the Company to procure a judgment in its favor by reason
of the fact that Indemnitee is or was a director and/or officer of the
Company, or is or was serving at the request of the Company as a director,
officer, employee or agent of another corporation, partnership, joint
venture, trust or other enterprise, against all Expenses actually and
reasonably incurred by Indemnitee in connection with the defense, settlement
or other disposition of such Proceeding, but only if he acted in good faith
and in a manner that he reasonably believed to be in or not opposed to the
best interests of the Company, except that no indemnification shall be made
under this Section 4 in respect of any claim, issue or matter as to which
Indemnitee shall have been adjudged to be liable to the Company unless and
only to the extent that the Delaware Court of Chancery or the court in which
such Proceeding was brought shall determine upon application that, despite
the adjudication of liability but in view of all the circumstances of the
case, Indemnitee is fairly and reasonably entitled to indemnity for such
Expenses as the Delaware Court of Chancery or such other court shall deem
proper.
5. INDEMNIFICATION FOR EXPENSES OF SUCCESSFUL PARTY. Notwithstanding
any other provision of this Agreement to the contrary, to the extent that
Indemnitee has been successful on the merits or otherwise in defense of any
Proceeding referred to in Sections 3 and/or 4 of this Agreement, or in
defense of any claim, issue or matter therein, including dismissal without
prejudice, Indemnitee shall be indemnified against all Expenses actually and
reasonably incurred by Indemnitee in connection therewith.
6. ADVANCES OF EXPENSES. The Expenses incurred by Indemnitee pursuant
to Sections 3 and/or 4 of this Agreement in connection with any Proceeding
shall, at the written request of the Indemnitee, be paid by the Company in
advance of the final disposition of such Proceeding upon receipt by the
Company of an undertaking by or on behalf of Indemnitee ("Indemnitee's
Undertaking") to repay such amount to the extent that it is ultimately
determined that Indemnitee is not entitled to be indemnified by the Company.
The request for advancement of Expenses by Indemnitee and the undertaking to
repay of Indemnitee, which need not be secured, shall be substantially in the
form of Exhibit A to this Agreement.
7. RIGHT OF INDEMNITEE TO INDEMNIFICATION OR ADVANCEMENT OF EXPENSES
UPON APPLICATION; PROCEDURE UPON APPLICATION.
(a) Any indemnification under Sections 3 and/or 4 of this Agreement
shall be made no later than 45 days after receipt by the Company of the
written request of
3
<PAGE>
Indemnitee, unless a determination is made within said
45-day period by (i) a majority vote of the directors of the Company who
are not parties to the involved Proceeding, even though less than a quorum,
or (ii) independent legal counsel in a written opinion (which counsel shall
be appointed if there are no such directors or if such directors so
direct), that the Indemnitee has not met the applicable standards for
indemnification set forth in Section 3 or 4, as the case may be.
(b) Any advancement of Expenses under Section 6 of this Agreement
shall be made no later than 10 days after receipt by the Company of
Indemnitee's Undertaking.
(c) In any action to establish or enforce the right of
indemnification or to receive advancement of Expenses as provided in this
Agreement, the burden of proving that indemnification or advancement of
Expenses is not appropriate shall be on the Company. Neither the failure
of the Company (including its board of directors or independent legal
counsel) to have made a determination prior to the commencement of such
action that indemnification or advancement of Expenses is proper in the
circumstances because Indemnitee has met the applicable standard of
conduct, nor an actual determination by the Company (including its board of
directors or independent legal counsel) that Indemnitee has not met such
applicable standard of conduct, shall be a defense to the action or create
a presumption that Indemnitee has not met the applicable standard of
conduct. Expenses incurred by Indemnitee in connection with successfully
establishing or enforcing his right of indemnification or to receive
advancement of Expenses, in whole or in part, under this Agreement shall
also be indemnified by the Company.
8. INDEMNIFICATION AND ADVANCEMENT OF EXPENSES UNDER THIS AGREEMENT
NOT EXCLUSIVE. The rights of indemnification and to receive advancement of
Expenses as provided by this Agreement shall not be deemed exclusive of any
other rights to which Indemnitee may be entitled under the Certificate of
Incorporation or Bylaws of the Company, any other agreement, any vote of
stockholders or disinterested directors, the General Corporation Law of the
State of Delaware, or otherwise, both as to action in his official capacity
and as to action in another capacity while holding such office.
9. PARTIAL INDEMNIFICATION. If Indemnitee is entitled under any
provision of this Agreement to indemnification or to receive advancement by
the Company for some or a portion of the Expenses, judgments, fines or
amounts paid in settlement actually and reasonably incurred by Indemnitee in
the investigation, defense, appeal, settlement or other disposition of any
Proceeding but not, however, for the total amount thereof, the Company shall
nevertheless indemnify Indemnitee for the portion thereof to which Indemnitee
is entitled.
10. RIGHTS CONTINUED. The rights of indemnification and to receive
advancement of Expenses as provided by this Agreement shall continue as to
Indemnitee even though Indemnitee may have ceased to be a director or officer
of the Company and shall inure to the benefit of Indemnitee's personal or
legal representatives, executors, administrators, successors, heirs,
distributees, devisees and legatees.
4
<PAGE>
11. NO CONSTRUCTION AS AN EMPLOYMENT AGREEMENT OR ANY OTHER COMMITMENT.
Nothing contained in this Agreement shall be construed as giving Indemnitee
any right to be retained in the employ of the Company or any of its
subsidiaries, if Indemnitee currently serves as an officer of the Company, or
to be renominated as a director of the Company, if Indemnitee currently
serves as a director of the Company.
12. LIABILITY INSURANCE. To the extent the Company maintains an
insurance policy or policies providing directors' and officers' liability
insurance, Indemnitee shall be covered by such policy or policies in
accordance with its or their terms, to the maximum extent of the coverage
available for any director or officer of the Company under such policy or
policies.
13. NO DUPLICATION OF PAYMENTS. The Company shall not be liable under
this Agreement to make any payment of amounts otherwise indemnifiable under
this Agreement if, and to the extent that, Indemnitee has otherwise actually
received such payment under any contract, agreement or insurance policy, the
Certificate of Incorporation or Bylaws of the Company, or otherwise.
14. SUBROGATION. In the event of payment under this Agreement, the
Company shall be subrogated to the extent of such payment to all the rights
of recovery of Indemnitee, who shall execute all papers required and shall do
everything that may be necessary to secure such rights, including without
limitation the execution of such documents as may be necessary to enable the
Company effectively to bring suit to enforce such rights.
15. EXCEPTIONS. Notwithstanding any other provision in this Agreement,
the Company shall not be obligated pursuant to the terms of this Agreement,
to indemnify or advance Expenses to the Indemnitee with respect to any
Proceeding, or any claim therein, (i) brought or made by Indemnitee against
the Company, or (ii) in which final judgment is rendered against the
Indemnitee for an accounting of profits made from the purchase and sale or
the sale and purchase by Indemnitee of securities of the Company pursuant to
the provisions of Section 16(b) of the Securities Exchange Act of 1934, as
amended, or similar provisions of any federal, state or local statute.
16. NOTICES. Any notice or other communication required or permitted
to be given or made to the Company or Indemnitee pursuant to this Agreement
shall be given or made in writing by depositing the same in the United States
mail, with postage thereon prepaid, addressed to the person to whom such
notice or communication is directed at the address of such person on the
records of the Company, and such notice or communication shall be deemed
given or made at the time when the same shall be so deposited in the United
States mail. Any such notice or communication to the Company shall be
addressed to the Secretary of the Company.
17. CONTRACTUAL RIGHTS. The right to be indemnified or to receive
advancement of Expenses under this Agreement (i) is a contract right based
upon good and valuable consideration, pursuant to which Indemnitee may sue,
(ii) is and is intended to be retroactive and shall be available as to events
occurring prior to the date of this Agreement and (iii) shall continue after
any rescission or restrictive modification of this Agreement as to events
occurring prior thereto.
5
<PAGE>
18. SEVERABILITY. If any provision or provisions of this Agreement
shall be held to be invalid, illegal or unenforceable for any reason
whatsoever, the validity, legality and enforceability of the remaining
provisions shall not in any way be affected or impaired thereby; and, to the
fullest extent possible, the provisions of this Agreement shall be construed
so as to give effect to the intent manifested by the provisions held invalid,
illegal or unenforceable.
19. SUCCESSORS; BINDING AGREEMENT. The Company shall require any
successor to all or substantially all of the business and/or assets of the
Company (whether direct or indirect, by purchase, merger, consolidation or
otherwise), by agreement in form and substance reasonably satisfactory to
Indemnitee, to expressly assume and agree to perform this Agreement in the
same manner and to the same extent that the Company would be required to
perform if no such succession had taken place. As used in this Agreement,
"Company" shall mean the Company as hereinbefore defined and any successor to
its business and/or assets as aforesaid which executes and delivers the
agreement provided for in this Section 19 or which otherwise becomes bound by
the terms and provisions of this Agreement by operation of law.
20. COUNTERPARTS, MODIFICATION, HEADINGS, GENDER.
(a) This Agreement may be executed in any number of counterparts,
each of which shall constitute one and the same instrument, and either
party hereto may execute this Agreement by signing any such counterpart.
(b) No provisions of this Agreement may be modified, waived or
discharged unless such waiver, modification or discharge is agreed to in
writing and signed by Indemnitee and an appropriate officer of the Company.
No waiver by any party at any time of any breach by any other party of, or
compliance with, any condition or provision of this Agreement to be
performed by any other party shall be deemed a waiver of similar or
dissimilar provisions or conditions at the same time or at any prior or
subsequent time.
(c) Section headings are not to be considered part of this Agreement,
are solely for convenience of reference, and shall not affect the meaning
or interpretation of this Agreement or any provision set forth herein.
(d) Pronouns in masculine, feminine and neuter genders shall be
construed to include any other gender, and words in the singular form shall
be construed to include the plural and vice versa, unless the context
otherwise requires.
21. ASSIGNABILITY. This Agreement shall not be assignable by either party
without the consent of the other.
6
<PAGE>
22. EXCLUSIVE JURISDICTION; GOVERNING LAW. The Company and Indemnitee
agree that all disputes in any way relating to or arising under this
Agreement, including, without limitation, any action for advancement of
Expenses or indemnification, shall be litigated, if at all, exclusively in
the Delaware Court of Chancery, and, if necessary, the corresponding
appellate courts. This Agreement shall be governed by and construed and
enforced in accordance with the laws of the State of Delaware applicable to
contracts made and to be performed in such state without giving effect to the
principles of conflicts of laws. The Company and Indemnitee expressly submit
themselves to the personal jurisdiction of the State of Delaware.
23. TERMINATION.
(a) This Agreement shall terminate upon the mutual agreement of the
parties that this Agreement shall terminate or upon the death of Indemnitee
or the resignation, retirement, removal or replacement of Indemnitee from
all of his positions as a director and/or officer of the Company.
(b) The termination of this Agreement shall not terminate:
(i) the Company's liability for claims or actions against
Indemnitee arising out of or related to acts, omissions, occurrences,
facts or circumstances occurring or alleged to have occurred prior to
such termination; or
(ii) the applicability of the terms and conditions of this
Agreement to such claims or actions.
IN WITNESS WHEREOF, the Company and Indemnitee have executed this Agreement
as of the date and year first above written.
NOBLE AFFILIATES, INC.
By:_________________________________
Name:_________________________
Title:________________________
INDEMNITEE
____________________________________
Name:_______________________________
7
<PAGE>
EXHIBIT A
INDEMNITEE'S UNDERTAKING
___________, 19__
Noble Affiliates, Inc.
110 West Broadway
Ardmore, Oklahoma 73401
RE: INDEMNITY AGREEMENT
Gentlemen:
Reference is made to the Indemnity Agreement dated as of ___________,
19__ by and between Noble Affiliates, Inc. and the undersigned Indemnitee,
and particularly to Section 6 thereof relating to advance payment by the
Company of certain Expenses incurred by the undersigned Indemnitee.
Capitalized terms used and not otherwise defined in this Indemnitee's
Undertaking shall have the respective meanings ascribed to such terms in the
Agreement.
The undersigned Indemnitee has incurred Expenses pursuant to Section 3
and/or 4 of the Agreement in connection with a Proceeding. The types and
amounts of Expenses are itemized on Attachment I to this Indemnitee's
Undertaking. The undersigned Indemnitee hereby requests that the total
amount of these Expenses (the "Advanced Amount") be paid by the Company in
advance of the final disposition of such Proceeding in accordance with the
Agreement.
The undersigned Indemnitee hereby agrees to repay the Advanced Amount to
the Company to the extent that it is ultimately determined that the
undersigned Indemnitee is not entitled to be indemnified by the Company.
This agreement of Indemnitee to repay shall be unsecured.
Very truly yours,
_________________________________
Signature
_________________________________
Name of Indemnitee (Type or Print)
<PAGE>
ATTACHMENT I TO
INDEMNITEE'S UNDERTAKING
ITEMIZATION OF
TYPES AND AMOUNTS OF EXPENSES
Attached hereto are receipts, statements or invoices for the following
qualifying Expenses which Indemnitee represents have been incurred by
Indemnitee in connection with a Proceeding:
TYPE AMOUNT
---- ------
1.
------
Total Advanced Amount
------
------
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
SIGNIFICANT EVENTS IN 1995
- - The Company had record levels of oil and gas production during 1995.
- - The Company expended $266 million on exploration, development and acquisition
costs during 1995.
- - The Company replaced production of its reserves in 1995 by 183 percent on a
barrel of oil equivalent (BOE) basis - gas converted at 6:1.
- - The cost of finding of all reserves added in 1995 was $5.64 per BOE.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $238.9 million for 1995, a 27
percent and 71 percent increase from the $188.6 million and $139.4 million in
1994 and 1993, respectively. Cash and short-term cash investments decreased to
$12.4 million at December 31, 1995, from $22.2 million at year-end 1994,
primarily as a result of higher drilling activity.
During 1995, the Company utilized its beginning cash balance and cash flow
from operations to fund its exploration, development and acquisition
expenditures. The Company's current ratio (current assets divided by current
liabilities) was 1.21:1 at December 31, 1995, compared with 1.64:1 at December
31, 1994.
RESERVES ADDED AND COST OF FINDING
During 1995, the Company spent $266 million on exploration, development and
acquisitions of oil and gas properties. Total proved gas reserves increased from
778.9 billion cubic feet (BCF) at year-end 1994 to 850.3 BCF at year-end 1995
and total proved oil reserves increased from 75.5 million barrels (BBLS) at
year-end 1994 to 84 million BBLS at year-end 1995.
An accepted method of calculating cost of finding is to divide the Company's
expenditures for oil and gas exploration, development and acquisitions by the
net BOE's added during the year. Using this method, the Company's cost of
finding for 1995 was $5.64 per BOE. A three year summary of cost of finding
follows:
<TABLE>
<CAPTION>
THREE
(BOE'S AND DOLLARS STATED IN MILLIONS, YEAR
EXCEPT FINDING COST) 1995 1994 1993 TOTAL
- -----------------------------------------------------------------------
<S> <C> <C> <C> <C>
Oil reserves added 18.2 11.5 33.3 63.0
Gas reserves added BOE (6:1) 29.0 29.4 66.9 125.3
- -----------------------------------------------------------------------
Total reserves added BOE 47.2 40.9 100.2 188.3
- -----------------------------------------------------------------------
Costs incurred in oil and gas
acquisition, exploration
and development activities $266 $190 $515 $971
Average finding cost per BOE $5.64 $4.64 $5.14 $5.16*
</TABLE>
*Three year average
LONG-TERM FINANCING
Total long-term debt at December 31, 1995 was virtually unchanged from the
prior year at $376,992,000. The ratio of long-term debt to book capital (defined
as the Company's long-term debt plus its equity) remained the same for both 1995
and 1994 at 48 percent.
The Company has outstanding $230,000,000 4 1/4% Convertible Subordinated
Notes Due 2003, which are convertible into common stock of the Company at any
time prior to maturity at $36.65 per share.
Also outstanding are $100,000,000 7 1/4% Notes Due 2023. The Company may not
redeem any portion of these notes prior to maturity.
The Company has a credit agreement with certain banks which provides for
maximum unsecured borrowings of $100 million at variable rates. The Company
borrowed $48 million on June 1, 1994, and used the proceeds, plus available cash
balances, to redeem its $125,000,000 10 1/8% Notes Due June 1, 1997.
(This page contained two graphs in the body of the text: Costs Incurred for
Acquisitions, Exploration and Development for three years and Average Finding
Cost Per BOE for three years)
<PAGE>
On September 29, 1995, the Company borrowed $25 million under its bank credit
agreement and used the proceeds to acquire three Gulf of Mexico properties. On
October 17, 1995 an additional $5 million was borrowed under the bank credit
agreement and the proceeds were used to fund current operations. Both the $25
million and $5 million loans were repaid on December 1, 1995.
The interest rate on the credit agreement is a variable rate based on the
lowest of three interest rate options. The weighted average interest rate on the
borrowings during 1995 was 7 percent.
During the next five years no principal payments of long-term debt are
required except for $48 million outstanding under the bank credit agreement,
which is due May 31, 1997.
OTHER
The Company follows an entitlements method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $12.3 million
and $11.7 million at December 31, 1995 and 1994, respectively, and estimated gas
imbalance liabilities were $11.4 million and $10.5 million at December 31, 1995
and 1994, respectively. These imbalances are valued at the amount which is
expected to be received or paid to settle the imbalances. The settlement of the
imbalances can occur either during, or at the end of the life of a well, on a
volume basis or by cash settlement. The Company does not expect that a
significant portion of the settlements will occur in any one year. Thus, the
Company believes the periodic settlement of gas imbalances will have little
impact on its liquidity.
The Company has sold a number of non-strategic oil and gas properties over
the past three years, recognizing a gain of $3,620,000, $254,000 and $1,264,000
for 1995, 1994 and 1993, respectively. Total amounts of oil and gas reserves
associated with these disposals during the last three years were 828,000 BBLS of
oil and 13.9 BCF of gas. The Company believes the disposal of non-strategic
properties furthers the goal of concentrating its efforts on its strategic
properties.
The Company has paid quarterly cash dividends of $.04 per share since August
21, 1989, and currently anticipates it will continue to pay quarterly dividends
of $.04 per share.
During 1995, the Company adopted Statement of Financial Accounting Standards
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" (SFAS No. 121). The effect of adopting SFAS No. 121
was to record a $59.5 million pretax write- down of certain long-lived assets.
For additional information on SFAS No. 121, see Note 9 to the financial
statements.
In October 1995, the Financial Accounting Standards Board issued SFAS No. 123
"Accounting for Stock-Based Compensation." The Company plans to adopt SFAS No.
123 during 1996 by electing to disclose the additional information required in
the footnotes to its financial statements as opposed to recognition as
compensation expense.
RESULTS OF OPERATIONS
NET INCOME AND REVENUES
1995 VERSUS 1994. Net income for 1995 was $4.1 million, or $.08 per share,
compared with $3.2 million, or $.06 per share in 1994. Without the net effect of
the two non-recurring events in 1995, the increase in net income was achieved
primarily through record oil and gas production and increased oil prices. Total
revenues were $487 million in 1995 and $358.4 million in 1994.
Oil and gas revenues were $328.1 million in 1995, an increase of $21.9
million or 7 percent, compared with 1994. Average oil price in 1995 was $16.78
per barrel, a 13 percent increase from the 1994 average of $14.90 per barrel.
Average gas price declined 13 percent in 1995 to $1.72 per thousand cubic feet
(MCF) from the 1994 average of $1.97 per MCF. Such decline was a reflection of
weaker pricing as a result of milder weather and excess gas in storage.
Gathering, marketing and processing revenues increased 157 percent, or $68.8
million, to $112.7 million in 1995 as compared with 1994 levels. This increase
reflects a full year
(This page contained three graphs in the body of the text: Gas Reserves Added
for three years; Oil Reserves Added for three years and Net Income for three
years.)
<PAGE>
of operations for Noble Gas Marketing, Inc. (NGM), a wholly owned subsidiary of
the Company, as well as operations for Noble Trading, Inc. (NTI), a wholly owned
subsidiary of the Company, which began operations in May 1995. Other income in
1995 was $46.2 million, compared with $8.3 million in 1994. This increase
resulted from the settlement of a Columbia Gas Transmission Corporation
bankruptcy claim with Samedan Oil Corporation (Samedan), in which $39 million
was recorded as other income.
1994 VERSUS 1993. Net income for 1994 was $3.2 million, or $.06 per share,
compared with $12.6 million, or $.26 per share in 1993. Although oil and gas
production increased for the year, higher exploration and depreciation,
depletion and amortization (DD&A) expenses caused a decrease in 1994 net income.
Total revenues were $358.4 million and $286.6 million in 1994 and 1993,
respectively.
Oil and gas revenues were $306.2 million in 1994, an increase of $28.2
million, or 10 percent greater than 1993. The average oil price in 1994 was
$14.90 per barrel, a 6 percent decrease from the 1993 average of $15.91 per
barrel. The average gas price declined 6 percent in 1994 to $1.97 per MCF from
the 1993 average of $2.10 per MCF.
Gathering, marketing and processing revenues were $43.9 million in 1994. This
reflects sales from NGM, which began operations in June 1994. Other income of
$8.3 million in 1994 was virtually flat with 1993 levels.
NATURAL GAS INFORMATION
1995 VERSUS 1994. Gas sales for 1995 decreased 4 percent to $167.4 million
from $174.5 million in 1994. Average daily production in 1995 increased 10
percent to 272.2 million cubic feet (MMCF) from 247.6 MMCF in 1994.
The average gas price in 1995 decreased 13 percent to $1.72 per MCF, from
$1.97 per MCF in 1994. In 1995, the Company's average gas prices ranged from a
low of $1.50 in February and August, to a high of $2.33 in December.
1994 VERSUS 1993. Gas sales for 1994 increased 10 percent to $174.5 million
from $159.2 million in 1993. Average daily production in 1994 increased 17
percent to 247.6 MMCF from 211.1 MMCF in 1993.
The average gas price in 1994 decreased 6 percent to $1.97 per MCF, from
$2.10 per MCF in 1993. In 1994, the Company's average gas prices ranged from a
low of $1.59 per MCF in October to a high of $2.34 per MCF in March.
A three-year summary of gas related information follows:
<TABLE>
<CAPTION>
1995 1994 1993
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at year end (MMCF) 850,339 778,950 691,530
Gas revenues (millions) $167.4 $174.5 $159.2
Average price per MCF* $ 1.72 $ 1.97 $ 2.10
Average daily production (MMCF) 272.2 247.6 211.1
Gas sales as a % of oil and gas sales 52% 59% 59%
</TABLE>
*The above amount reflects a reduction of $.004 per MCF in 1995 and $.048 per
MCF in 1993 from hedging.
CRUDE OIL INFORMATION
1995 VERSUS 1994. Oil sales for 1995 increased 25 percent to $153.5 million
from $122.9 million in 1994. Average daily production in 1995 increased 13
percent to 25,617 barrels from 22,751 barrels in 1994.
Average oil price for 1995 was $16.78 a barrel, a 13 percent increase from
the 1994 average of $14.90 per barrel. The Company believes prices should
improve moderately over time, but when conditions warrant, hedging may be used
to minimize exposure to price volatility.
International sales accounted for 15 percent of 1995 oil sales compared with
16 percent of oil sales in 1994. Average daily oil production from properties
outside the United States was 3,777 barrels in 1995 and 3,329 barrels in 1994.
1994 VERSUS 1993. Oil sales for 1994 increased 10 percent to $122.9 million
from $111.3 million in 1993. Average daily production in 1994 increased 17
percent to 22,751 barrels from 19,496 barrels in 1993.
Average oil price for 1994 was $14.90 a barrel, a 6 percent decrease from
the 1993 average of $15.91 per barrel.
International sales accounted for 16 percent of 1994 oil sales, compared with
19 percent of oil sales in 1993. Average daily oil production from properties
outside the United States was 3,329 barrels in 1994 and 3,465 barrels in 1993.
A three-year summary of oil related information follows:
<TABLE>
<CAPTION>
1995 1994 1993
- ------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at year end
(thousands of barrels)
Working interest 80,910 73,147 70,245
Royalty interest (1) 3,098 2,380 2,710
- ------------------------------------------------------------------
Total 84,008 75,527 72,955
- ------------------------------------------------------------------
- ------------------------------------------------------------------
Oil revenues (millions) $153.5 $122.9 $111.3
Average price per BBL (2) $16.78 $14.90 $15.91
Average daily production (BBLS) 25,617 22,751 19,496
Oil sales as a % of
oil and gas sales 48% 41% 41%
</TABLE>
(1) Includes royalty oil, condensate and gas reserves stated in BOE's.
(2) Includes $.16 per barrel in 1995 and $.02 per barrel in 1993 from hedging
income.
(This page contain two graphs in the body of the text: Gas Revenues for three
years and Oil Revenues for three years.)
<PAGE>
HEDGING ACTIVITY
1995 VERSUS 1994. The Company, through its two subsidiaries, NGM and Samedan,
uses hedging arrangements in connection with the sale of oil and gas in order to
obtain a fixed margin and/or minimize product price risk.
Most of the gas purchased by NGM, which includes substantially all of
Samedan's gas as well as certain other third party gas, is purchased on an index
basis; however, purchasers in the markets in which NGM sells may often require
fixed or NYMEX related pricing. NGM can use a hedge to convert the fixed or
NYMEX sale to an index basis thereby determining the margin and minimizing the
risk of price volatility. During 1995, NGM had hedging transactions with large
financial institutions that averaged approximately 126,000 MMBTU's of gas per
day at prices linked to certain indices. Hedges for January through December
1996, which range from 10,000 to approximately 222,000 MMBTU's of gas per day at
prices ranging from $.75 per MMBTU above index to $1.10 per MMBTU below index,
were not closed at December 31, 1995. These hedges are in place to secure
margins on future physical transactions. NGM records hedging gains or losses
relating to fixed term sales as gathering, marketing and processing revenues in
the periods in which the related contract is completed.
Samedan, from time to time, may enter into hedging arrangements to protect
against oil and gas price volatility, and records hedging gains and losses
relating to its own oil and gas production in oil and gas sales and royalties.
Samedan had fixed price hedges for 30,000 MMBTU's of gas per day for November
and 100,000 MMBTU's of gas per day for December 1995 at prices ranging from
$1.82 to $1.95 per MMBTU. Samedan also had various collar transactions for
November and December 1995 for 25,000 MMBTU's of gas per day which had a floor
price of $1.60 and a ceiling price of $1.96 per MMBTU. Gas revenues for 1995
reflect reduced value of $435,000 relating to hedging production at prices below
the ultimate spot price for gas. This lowered the average gas price received by
$.004 per MCF. Hedges for January through December 1996, which range from
205,000 to 230,000 MMBTU's of gas per day at prices ranging from $1.60 to $2.03
per MMBTU, were not closed at December 31, 1995.
Samedan had oil hedges of 5,000 barrels per day for May through December
1995. These hedges ranged in price from $18.56 to $20.27 per barrel. Various
collar transactions for January through December 1996 of 15,000 barrels per day,
which have a floor price of $16.50 per barrel and ceiling prices ranging from
$18.00 to $18.60 per barrel, were not closed at December 31, 1995. The Company's
oil revenue in 1995 includes approximately $1.4 million of hedging income, which
increased the average oil price by $.16 per barrel. For additional hedging
disclosures, see Notes 1, 2 and 8 to the financial statements.
1994 VERSUS 1993. During 1994, all gas hedging activity related to NGM sales,
which hedged an average of approximately 32,000 MMBTU's of gas per day at prices
ranging from $.01 per MMBTU above index to $.58 per MMBTU above index. Hedging
gains and losses for 1994 are included in gathering, marketing and processing
revenues. The average gas price in 1993 reflected $3.7 million of reduced value
relating to hedging, which lowered the average gas price by $.048 per MCF.
The Company did not hedge any of its oil production during 1994. Oil revenues
for 1993 include approximately $100,000 of hedging income, which increased
average oil price by $.02 per barrel.
COSTS AND EXPENSES
1995 VERSUS 1994. Oil and gas exploration expense in 1995 decreased $21.1
million from 1994 to $33.2 million. The decrease resulted from a $17.7 million
decrease in dry hole expense in 1995, a $2.5 million decrease in abandoned
assets, and a $1.3 million decrease in undeveloped lease amortization.
Oil and gas operations expense in 1995 increased $7 million over 1994 to
$81.7 million. Lease operating expense increased $9.3 million in 1995 primarily
due to higher oil and gas production from a greater number of properties. This
increase was partially offset by a $2.5 million decrease in production taxes
paid, resulting from a contractual tax reimbursement from a purchaser.
In 1995, DD&A expense increased $73.4 million over 1994 to $200.9 million.
This increase resulted principally as a result of adoption of SFAS No. 121 in
the fourth quarter of 1995, in which a pretax charge of $59.5 million was
recorded to DD&A expense. The charge reduced 1995 net income by $38.7 million,
or $.77 per share. The pretax charge includes $4.1 million and $3.2 million
related to Samedan Oil of Canada, Inc. and Samedan of Tunisia, Inc.,
respectively, both wholly owned subsidiaries of the Company. The unit rate of
DD&A expense per BOE, converting gas to oil on a 6:1 basis, was $7.75 for 1995,
compared to $5.46 for 1994. The DD&A unit rate without the effect of SFAS No.
121 would have also been $5.46 in 1995. Higher oil and gas volumes also
contributed to the higher DD&A expense in 1995.
(This page contained one graph in the body of the text: DD&A Expense Per BOE of
Production for three years.)
<PAGE>
The Company provides for the cost of future liabilities related to
restoration and dismantlement costs for offshore facilities. This provision is
based on the Company's best estimate of such costs to be incurred in future
years based on information from the Company's engineers. These estimated costs
are provided through charging DD&A expense using a ratio of production divided
by reserves multiplied by the estimated costs to dismantle and restore. The
Company has provided $40.6 million for such future costs which are classified in
accumulated DD&A on the balance sheet. Total estimated future dismantlement and
restoration costs of $84.3 million are included in future production and
development costs for purposes of estimating the future net revenues relating to
the Company's proved reserves.
1994 VERSUS 1993. Oil and gas exploration expense in 1994 increased $17.8
million over 1993 to $54.3 million. The increase resulted from a $21.3 million
increase in dry hole expense, which was partially offset by a $4.3 million
decrease in undeveloped lease amortization. Dry hole expense increased as a
result of higher exploration activity during 1994.
In 1994, oil and gas operations expense decreased $449,000 from 1993 to $74.7
million. This decrease occurred in spite of increased oil and gas production and
can be explained by several factors. First, international operations expense in
1994 decreased approximately $3 million due to the sale of the Company's Camar
prospect in Indonesia, as well as lower operating costs incurred in the
Company's remaining international operations. Second, in the fourth quarter of
1993, operations expense reflected expenses being charged to the Company on
acquired properties. In 1994, the Company absorbed the operations for these
acquired properties with little incremental costs, resulting in limited
increases in operations expense notwithstanding increased production. Third, in
1994, the Company incurred fewer workover expenses, thereby reducing operations
expense from 1993 levels.
DD&A expense in 1994 increased $20.3 million over 1993 to $127.5 million.
This increase resulted primarily from higher oil and gas production volumes from
properties acquired in late 1993, along with increases due to reserve writedowns
of $6.8 million on three offshore Louisiana blocks and approximately $3 million
on other properties. Total estimated future dismantlement and restoration costs
of $75.6 million are included in future production and development costs for
purposes of estimating the future net revenues relating to the Company's proved
reserves.
In 1994, selling, general and administrative (SG&A) expense increased $4.6
million over 1993 to $36.4 million. This increase was due, in part, to the
start-up operations of NGM, which sustained $1.2 million in SG&A expense, along
with an additional $2.2 million incurred by the Company's various divisions
which hired additional personnel to oversee increased operations.
INTEREST EXPENSE
1995 VERSUS 1994. In 1995, interest expense decreased $2.8 million from 1994
to $21.9 million. This decrease was due primarily to the redemption in June 1994
of the Company's $125,000,000 10 1/8% Notes Due June 1, 1997.
Capitalized interest in 1995 decreased $4.1 million from 1994 to $3.1
million. This decrease is primarily from a $4.9 million decrease in interest
capitalized on East Cameron blocks 320, 331 and 332.
1994 VERSUS 1993. In 1994, interest expense increased $4.3 million over 1993
to $24.7 million. This increase was due, in part, to recognizing a full year's
interest on the Company's $330 million of notes issued in late 1993, which
caused an increase of $13.7 million. Offsetting the increase was a decrease of
$7.4 million attributable to redemption in June 1994 of the Company's
$125,000,000 10 1/8% Notes Due June 1, 1997 and an additional decrease of $2.5
million resulting from redemption in May 1993 of the Company's $100,000,000 7
1/4% Convertible Debentures Due 2012.
Capitalized interest in 1994 increased $2.1 million over 1993 to $7.2
million. This increase is primarily due to a $1.4 million increase in
capitalized interest on East Cameron blocks 320, 331 and 332.
MARKETING SUBSIDIARIES
In June 1994, NGM began marketing the Company's natural gas as well as
certain other third-party gas. NGM sells gas directly to end-users, gas
marketers, industrial users, interstate and intrastate pipelines, and local
distribution companies. The Company records all of NGM's sales as gathering,
marketing and processing revenues. All intercompany sales and expenses have been
eliminated.
During 1995, NGM recorded $104.6 million in gathering, marketing and
processing revenues and $100.6 million in gathering, marketing and processing
expenses, generating a gross margin of $4 million for the year. The gross margin
was offset by administrative expenses of $1.6 million, resulting in pretax
income of $2.4 million for its second year of operation.
(This page contained one graph in the body of the text: SG&A Expense Per BOE of
Production for three years.)
<PAGE>
In 1994, NGM recorded $43.9 million in gathering, marketing and processing
revenues and $42.8 million in gathering, marketing and processing expenses,
generating a gross margin of $1.1 million for the year. The gross margin was
offset by administrative expenses of $1.2 million, resulting in a slight loss
for NGM's initial year of operation.
In May 1995, NTI began marketing a portion of the Company's oil as well as
certain third-party oil. The Company records all of NTI's sales as gathering,
marketing and processing revenues. All intercompany sales and expenses have been
eliminated.
During 1995, NTI recorded $8.1 million in gathering, marketing and processing
revenues and $7.3 million in gathering, marketing and processing expenses,
generating a gross margin of $791,000 for the year. The gross margin was offset
by administrative expenses of $52,000, resulting in pretax income of $739,000
for NTI's initial year of operation.
FUTURE TRENDS
The Company expects higher revenues in 1996 compared with 1995 levels. The
increases in revenues are expected primarily due to projected higher production
levels and slightly higher average prices.
The Company's average production and lifting cost per BOE and SG&A expense
per BOE of production have decreased each year for the past three years.
Lower DD&A unit rates are expected in 1996, in part due to the lower cost
basis of certain oil and gas assets as a result of the SFAS No. 121 impairment
of $59.5 million of long-lived assets during 1995.
The projected increases in revenues should have a positive affect on net
income and cash flows in 1996 compared to 1995.
The Company recently set its 1996 capital budget at $240 million. Such
capital budget, as well as exploration expenditures, are planned to be funded
through internally generated cash flows. The Company plans an active exploration
and development program in its domestic onshore and offshore divisions along
with its Canadian and Equatorial Guinea operations.
Over the past several years, Samedan has settled various claims which it had
against parties who had contracted to purchase gas at fixed prices which were
greater than market, or who had take-or-pay contracts with Samedan in which such
obligations to take-or-pay for quantities of gas were not fulfilled. It is the
Company's policy, which is consistent with general industry practice, that such
payments do not represent payment for gas produced and therefore, are not
subject to royalty payments. The federal government, with respect to leases on
both onshore and offshore federal lands, certain other governmental bodies, and
some private landowners have begun to assert claims in recent years against oil
and gas companies for royalties on some or all of such settlement amounts.
The Company recently participated in a joint effort with the Independent
Petroleum Association of America wherein Samedan was a party to a test case
involving such a claim made with respect to a lease on Indian lands. In the U.S.
District Court for the District of Columbia, Samedan and other plaintiffs
challenged the determination by the U.S. Minerals Management Service (MMS) that
royalties were payable to the government on certain proceeds received by Samedan
(and the other plaintiffs) with respect to a contract settlement. The district
court recently ruled in favor of the MMS, and a judgment in the amount of
$20,000 was awarded against Samedan. Samedan has appealed this judgment and
intends to vigorously pursue its appeal. The Company intends to continue to
follow its current policies in regard to these matters unless and until the
issues have been settled by controlling precedent.
Although the amount in controversy applicable to Samedan in the above
described lawsuit is not material, the decision in such case, if not reversed or
otherwise limited on appeal, could have a negative impact with respect to other
take-or-pay or contract settlements entered into by Samedan. There can be no
assurance that Samedan will prevail on appeal in the above described lawsuit or
that Samedan will prevail in the future on any similar claims asserted against
it based on other take-or-pay or contract settlements. The Company is unable at
this time to estimate the possible amount of the loss, if any, associated with
this contingency.
Management believes that the Company is well positioned with its balanced
reserves of oil and gas to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to affect the
domestic oil and gas industry. Due to the volatility of oil and gas prices, the
Company, from time to time, has used hedging and plans to do so in the future as
a means of controlling its exposure to price changes. The Company cannot predict
the extent to which its revenues will be affected by inflation, government
regulation or changing prices.
(This page contained one graph in the body of the text: Average Production and
Lifting Cost Per BOE for three years.)
<PAGE>
SELECTED FINANCIAL DATA NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) 1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
REVENUES AND INCOME
Revenues . . . . . . . . . . . . . . . . . . . . $487,018 $358,389 $ 286,583 $303,782 $250,417
Net cash provided by operating activities. . . . 238,920 188,621 139,381 125,107 89,179
Net income . . . . . . . . . . . . . . . . . . . 4,086 3,166 12,625 41,240 19,308
PER SHARE DATA
Net income . . . . . . . . . . . . . . . . . . . $ .08 $ .06 $ .26 $ .93 $ .44
Cash dividends . . . . . . . . . . . . . . . . . .16 .16 .16 .16 .16
Year end stock prices. . . . . . . . . . . . . . 29.88 24.75 26.50 17.63 13.63
Average shares outstanding . . . . . . . . . . . 50,046 49,970 48,098 44,341 44,135
FINANCIAL POSITION
Property, pland and equipment, net:
Oil and gas mineral interests,
equipment and facilities . . . . . . . . . . $831,827 $804,009 $ 784,235 $409,740 $458,892
Total assets . . . . . . . . . . . . . . . . . . 989,176 933,516 1,067,996 625,621 589,642
Long-term obligations:
Long-term debt . . . . . . . . . . . . . . . . 376,992 376,956 453,760 224,793 224,746
Deferred income taxes. . . . . . . . . . . . . 69,445 61,802 45,108 33,378 35,227
Other. . . . . . . . . . . . . . . . . . . . . 33,650 19,455 7,158 7,010 8,488
Shareholders' equity . . . . . . . . . . . . . . 411,911 412,066 415,432 304,779 264,509
Ratio of long-term debt to
book capital . . . . . . . . . . . . . . . . . .48 .48 .52 .42 .46
CAPITAL EXPENDITURES
Oil and gas mineral interests,
equipment and facilities . . . . . . . . . . . $252,977 $158,973 $ 508,506 $ 64,066 $121,378
Other. . . . . . . . . . . . . . . . . . . . . . 6,265 2,371 1,607 1,744 3,970
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
Total capital expenditures $259,242 $161,344 $ 510,113 $ 65,810 $125,348
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
GAS
Sales (in millions). . . . . . . . . . . . . . . . $ 167.4 $ 174.5 $ 159.2 $ 134.2 $ 111.1
Production (MMCF per day). . . . . . . . . . . . . 272.2 247.6 211.1 204.6 178.4
Average price (per MCF). . . . . . . . . . . . . . $ 1.72 $ 1.97 $ 2.10 $ 1.81 $ 1.74
OIL
Sales (in millions). . . . . . . . . . . . . . . . $ 153.5 $ 122.9 $ 111.3 $ 120.2 $ 109.2
Production (BBLS per day). . . . . . . . . . . . . 25,617 22,751 19,496 17,826 15,001
Average price (per BBL). . . . . . . . . . . . . . $ 16.78 $ 14.90 $ 15.91 $ 18.68 $ 20.39
Royalty sales (in millions). . . . . . . . . . . . $ 7.2 $ 8.8 $ 7.5 $ 5.4 $ 6.2
</TABLE>
<PAGE>
CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
DECEMBER 31,
- -------------------------------------------------------------------------------------------------------
(IN THOUSANDS OF DOLLARS) 1995 1994
- -------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and short-term cash investments $ 12,429 $ 22,192
Accounts receivable - trade 79,478 49,692
Materials and supplies inventories 2,855 3,591
Other current assets 22,750 28,412
- -------------------------------------------------------------------------------------------------------
Total current assets 117,512 103,887
- -------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 1,658,157 1,560,392
Other 33,328 28,067
- -------------------------------------------------------------------------------------------------------
1,691,485 1,588,459
Accumulated depreciation, depletion and amortization (847,540) (775,079)
- -------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 843,945 813,380
- -------------------------------------------------------------------------------------------------------
OTHER ASSETS 27,719 16,249
- -------------------------------------------------------------------------------------------------------
$ 989,176 $ 933,516
- -------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 73,536 $ 46,473
Other current liabilities 20,206 12,996
Income taxes - current 3,436 3,768
- -------------------------------------------------------------------------------------------------------
Total current liabilities 97,178 63,237
- -------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES 69,445 61,802
- -------------------------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 33,650 19,455
- -------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 376,992 376,956
- -------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY:
Preferred stock - par value $1; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized;
51,722,647 and 51,537,455 shares issued in 1995 and 1994, respectively 172,407 171,790
Capital in excess of par value 145,059 141,911
Retained earnings 109,863 113,783
- -------------------------------------------------------------------------------------------------------
427,329 427,484
Less common stock in treasury, at cost (1995 and 1994, 1,524,900 shares) (15,418) (15,418)
- -------------------------------------------------------------------------------------------------------
Total shareholders' equity 411,911 412,066
- -------------------------------------------------------------------------------------------------------
$ 989,176 $ 933,516
- -------------------------------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- ---------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1995 1994 1993
- ---------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales and royalties $328,134 $306,169 $278,004
Gathering, marketing and processing 112,702 43,921
Other income 46,182 8,299 8,579
- ---------------------------------------------------------------------------------
487,018 358,389 286,583
- ---------------------------------------------------------------------------------
COSTS AND EXPENSES:
Oil and gas exploration 33,246 54,321 36,473
Oil and gas operations 81,735 74,661 75,110
Gathering, marketing and processing 107,867 42,758
Depreciation, depletion and amortization 200,914 127,470 107,215
Selling, general and administrative 36,514 36,408 31,784
Interest 21,871 24,729 20,402
Interest capitalized (3,127) (7,183) (5,060)
- ---------------------------------------------------------------------------------
479,020 353,164 265,924
- ---------------------------------------------------------------------------------
INCOME BEFORE TAXES 7,998 5,225 20,659
- ---------------------------------------------------------------------------------
INCOME TAX PROVISIONS:
Current (9,123) (10,462) 558
Deferred 13,035 12,521 7,476
- ---------------------------------------------------------------------------------
3,912 2,059 8,034
- ---------------------------------------------------------------------------------
NET INCOME $ 4,086 $ 3,166 $ 12,625
- ---------------------------------------------------------------------------------
NET INCOME PER SHARE $ .08 $ .06 $ .26
- ---------------------------------------------------------------------------------
AVERAGE NUMBER SHARES OUTSTANDING 50,046 49,970 48,098
- ---------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
- ------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS OF DOLLARS) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 4,086 $ 3,166 $ 12,625
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 200,914 127,470 107,215
Amortization of undeveloped lease costs, net 6,465 7,813 12,063
(Gain) loss on disposal of assets (3,289) 2,213 4,821
Noncurrent deferred income taxes 7,642 16,694 11,730
Increase in other deferred credits 14,194 12,297 148
(Increase) decrease in other (399) 8,232 3,744
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable (29,786) 16,622 (4,445)
(Increase) decrease in other current assets 5,151 (18,185) (5,789)
Increase (decrease) in accounts payable 27,063 17,119 (194)
Increase (decrease) in other current liabilities 6,879 (4,820) (2,537)
- ------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 238,920 188,621 139,381
- ------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (255,188) (166,121) (508,506)
Proceeds from sale of property, plant and equipment 10,745 2,392 10,606
- ------------------------------------------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (244,443) (163,729) (497,900)
- ------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Exercise of stock options 3,766 1,463 5,647
Cash dividends paid (8,006) (7,995) (7,766)
Proceeds from bank borrowings 30,000 48,000
Repayment of bank debt (30,000)
(Retirement of) proceeds from issuance of long-term debt (125,000) 324,589
(Retirement of) proceeds from short-term debt for property acquisition (95,600) 95,600
Cash redemption of convertible debt (1,845)
- ------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (4,240) (179,132) 416,225
- ------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS (9,763) (154,240) 57,706
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 22,192 176,432 118,726
- ------------------------------------------------------------------------------------------------------------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 12,429 $ 22,192 $ 176,432
- ------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 17,659 $ 18,603 $ 13,335
Income taxes $ 660 $ 5,300
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY NOBLE AFFILIATES, INC. AND
SUBSIDIARIES
<TABLE>
<CAPTION>
COMMON STOCK CAPITAL IN TREASURY
-------------------------- EXCESS OF STOCK AT RETAINED
(IN THOUSANDS OF DOLLARS) SHARES ISSUED AMOUNT PAR VALUE COST EARNINGS
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
JANUARY 1, 1993 46,132,342 $153,772 $ 52,672 $(15,418) $113,753
- -------------------------------------------------------------------------------------------------------
Net Income 12,625
Exercise of stock options 327,407 1,092 4,555
Redemption of convertible debentures 5,001,373 16,671 83,476
Cash dividends ($ .16 per share) (7,766)
- -------------------------------------------------------------------------------------------------------
DECEMBER 31, 1993 51,461,122 $171,535 $140,703 $(15,418) $118,612
- -------------------------------------------------------------------------------------------------------
Net Income 3,166
Exercise of stock options 76,333 255 1,208
Cash dividends ($ .16 per share) (7,995)
- -------------------------------------------------------------------------------------------------------
DECEMBER 31, 1994 51,537,455 $171,790 $141,911 $(15,418) $113,783
- -------------------------------------------------------------------------------------------------------
Net Income 4,086
Exercise of stock options 185,192 617 3,148
Cash dividends ($ .16 per share) (8,006)
- -------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995 51,722,647 $172,407 $145,059 $(15,418) $109,863
- -------------------------------------------------------------------------------------------------------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLAR AMOUNTS IN TABLES, UNLESS OTHERWISE INDICATED, ARE IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
The consolidated accounts include Noble Affiliates, Inc. (the Company) and
the consolidated accounts of its wholly owned subsidiaries: Noble Gas Marketing,
Inc. (NGM); Noble Trading, Inc. (NTI); NPM, Inc.; and Samedan Oil Corporation
(Samedan). Listed below are consolidated entities at December 31, 1995.
NOBLE AFFILIATES, INC.
Noble Gas Marketing, Inc.
Noble Gas Pipeline, Inc.
Noble Trading, Inc.
NPM, Inc.
Samedan Oil Corporation
Samedan Oil of Canada, Inc.
Samedan Oil of Indonesia, Inc.
Samedan of North Africa, Inc.
Samedan LPG
Samedan Pipe Line Corporation
Samedan Royalty Corporation
Samedan of Tunisia, Inc.
NATURE OF OPERATIONS
The Company is principally engaged, through its subsidiaries, in the
exploration, development, production and marketing of oil and gas. Samedan
operates throughout the major basins in the United States, including the Gulf of
Mexico, as well as Canada, Tunisia and Equatorial Guinea. The Company markets
its oil and gas production through NGM, NTI and Samedan.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities. Such estimates and
assumptions also affect the disclosure of contingent assets and liabilities at
the date of the financial statements as well as amounts of revenues and expenses
recognized during the reporting period. Of the estimates and assumptions that
affect reported results, the estimate of the Company's oil and gas reserves is
the most significant.
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is considered the functional currency for each of the
Company's international operations with the exception of Canada. The functional
currency for the Canadian subsidiary is the Canadian dollar which has been
translated into the U.S. dollar for the financial statements. Translation gains
or losses were not material in any of the periods presented.
INVENTORIES
Materials and supplies inventories consisting principally of tubular goods
and production equipment are stated at the lower of cost or market, with cost
being determined by the first-in, first-out method.
PROPERTY, PLANT AND EQUIPMENT
The Company accounts for its oil and gas properties under the successful
efforts method of accounting. Under this method, costs to acquire mineral
interests in oil and gas properties, to drill and equip exploratory wells that
find proved reserves and to drill and equip development wells are capitalized.
Capitalized costs of producing oil and gas properties are amortized to
operations by the unit-of-production method based on proved developed oil and
gas reserves on a property by property basis as estimated by Company engineers.
Estimated future restoration and abandonment costs are recorded by charges to
depreciation, depletion and amortization expense over the productive lives of
the related properties. The Company has provided $40.6 million for such future
costs classified with accumulated DD&A in the balance sheet. The total estimated
future dismantlement and restoration costs of $84.3 million are included in
future production and development costs for purposes of estimating the future
net revenues relating to the Company's proved reserves. Upon sale or retirement
of depreciable or depletable property, the cost and related accumulated DD&A are
eliminated from the accounts and the resulting gain or loss is recognized.
Undeveloped oil and gas properties, which are individually significant, are
periodically assessed for impairment of value and a loss is recognized at the
time of impairment by providing an impairment allowance. Other undeveloped
properties are amortized on a composite method based on the Company's experience
of successful drilling and average
<PAGE>
holding period. Geological and geophysical costs, delay rentals and costs to
drill exploratory wells which do not find proved reserves are expensed.
Developed oil and gas properties and other long-lived assets are periodically
assessed to determine if circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company performs this review of recoverability
by estimating future cash flows. If the sum of the expected future cash flows is
less than the carrying amount of the asset, an impairment is recognized based on
the discounted amount of such cash flows.
Repairs and maintenance are charged to expense as incurred. Renewals and
betterments are capitalized.
INCOME TAXES
The Company files a consolidated federal income tax return. Deferred income
taxes are provided for temporary differences between the financial reporting and
tax bases of the Company's assets and liabilities.
NET INCOME PER SHARE
Net income per share of common stock has been computed on the basis of the
weighted average number of shares outstanding during each period. The effect of
shares issuable upon the exercise of stock options is immaterial. The
convertible subordinated notes, which are not common stock equivalents, have not
been included in computing fully diluted earnings per share since their
inclusion would be antidilutive.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the acquisition or
construction of significant oil and gas properties.
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, cash and short-term cash investments
include cash on hand and investments purchased with original maturities of three
months or less.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan has a gas sales contract with NGM, whereby Samedan is paid an index
price for all gas sold to NGM. NGM records sales, including hedging
transactions, as gathering, marketing and processing revenues. NGM records as
cost of sales in gathering, marketing and processing costs, the amount paid to
Samedan and third parties. All intercompany sales and costs have been
eliminated.
The Company follows an entitlements method of accounting for its gas
imbalances. Gas imbalances occur when the Company sells more or less gas than
its entitled ownership percentage of total gas production. Any excess amount
received above the Company's share is treated as a liability. If less than the
Company's entitlement is received, the underproduction is recorded as a
receivable. The Company records the noncurrent liability in Other Deferred
Credits and Noncurrent Liabilities, and the current liability in Other Current
Liabilities. The Company's gas imbalance liabilities were $11.4 million and
$10.5 million for 1995 and 1994, respectively. The Company records the
noncurrent receivable in Other Assets, and the current receivable in Other
Current Assets. The Company's gas imbalance receivables were $12.3 million and
$11.7 million for 1995 and 1994, respectively, and are valued at the amount
which is expected to be received.
TAKE-OR-PAY SETTLEMENTS
The Company records gas contract settlements which are not subject to
recoupment in Other Income when the settlement is received.
TRADING AND HEDGING ACTIVITIES
The Company through its two subsidiaries, NGM and Samedan, uses hedging
arrangements in connection with the sale of oil and gas in order to obtain a
fixed margin and/or minimize product price risk. NGM markets substantially all
the natural gas produced by Samedan as well as certain gas produced by third
parties.
<PAGE>
Most of the gas purchased by NGM is on an index basis; however, purchasers in
the markets in which NGM sells may require fixed or NYMEX related pricing. NGM
can use a hedge to convert the fixed or NYMEX sale to an index basis thereby
determining the margin and minimizing the risk of price volatility. During 1995,
NGM had hedging transactions with large financial institutions that averaged
approximately 126,000 MMBTU's of gas per day at prices linked to certain
indices. These hedges were in place to secure margins on future physical
transactions. NGM records hedging gains or losses relating to fixed term sales
as gathering, marketing and processing revenues in the periods in which the
related contract is completed. Hedges for January through December 1996, which
range from 10,000 to approximately 222,000 MMBTU's of gas per day at prices
ranging from $.75 per MMBTU above index to $1.10 per MMBTU below index, were not
closed at December 31, 1995.
Samedan, from time to time, enters into hedging arrangements primarily to
protect against oil and gas price volatility and records hedging gains and
losses relating to its own oil and gas production in oil and gas sales and
royalties. Samedan had hedges of 5,000 barrels of oil per day for May through
December 1995. The hedged prices for this time period ranged from $18.56 per
barrel to $20.27 per barrel. Samedan also had in place, as of December 31, 1995,
various collar transactions which have a floor price of $16.50 per barrel and
ceiling prices ranging from $18.00 to $18.60 for volumes of 15,000 barrels per
day for January through December 1996.
Samedan had fixed price hedges for 30,000 MMBTU's of gas per day for November
and 100,000 MMBTU's of gas per day for December 1995 at prices ranging from
$1.82 to $1.95 per MMBTU. Samedan also had various collar transactions for
November and December 1995 for 25,000 MMBTU's of gas per day which had a floor
price of $1.60 and a ceiling price of $1.96 per MMBTU. Samedan has entered into
fixed price and collar hedges for gas as follows during 1996:
<TABLE>
<CAPTION>
VOLUMES FIXED
PERIODS MMBTU'S PER DAY PRICE RANGE
- -------------------------------------------------------------
<S> <C> <C>
January - December 1996 100,000 $1.78 - $1.80
COLLAR RANGES
-------------
January - October 1996 130,000 $1.60 - $2.03
November - December 1996 105,000 $1.60 - $2.03
</TABLE>
SELF-INSURANCE
The Company self-insures the medical and dental coverage provided to certain
of its employees, certain workers compensation and the first $250,000 of its
general liability coverage.
A provision for self-insured claims is recorded when sufficient information
is available to reasonably estimate the amount of the loss.
RECLASSIFICATION
Certain reclassifications have been made to the 1994 Consolidated Financial
Statements to conform to the 1995 presentation.
NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments pursuant to the requirements of SFAS No.
107, "Disclosures about Fair Value of Financial Instruments."
CASH AND SHORT-TERM CASH INVESTMENTS
The carrying amount approximates fair value due to the short maturity of the
instruments.
OIL AND GAS PRICE HEDGE AGREEMENTS
The fair value of oil and gas price hedges is the estimated amount the
Company would receive or pay to terminate the hedge agreements at the
reporting date taking into account the creditworthiness of the hedging
parties.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on the
quoted market prices for the same or similar issues or on the current
rates offered to the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company's financial
instruments are as follows:
<TABLE>
<CAPTION>
1995 1994
--------------------- ---------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
- -----------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash and short-term
cash investments $ 12,429 $ 12,429 $ 22,192 $ 22,192
Oil and gas hedge
agreements $ (7,867) $ 56
Long-term debt $376,992 $379,812 $376,956 $321,325
</TABLE>
<PAGE>
NOTE 3 - DEBT
A summary of debt at December 31 follows:
<TABLE>
<CAPTION>
1995 1994
- -----------------------------------------------------------
<S> <C> <C>
4 1/4% Convertible Subordinated
Notes Due 2003 $230,000 $230,000
7 1/4% Notes Due 2023 100,000 100,000
Bank Credit Agreement 48,000 48,000
- -----------------------------------------------------------
378,000 378,000
Less: unamortized discount 1,008 1,044
- -----------------------------------------------------------
Total long-term debt $376,992 $376,956
- -----------------------------------------------------------
</TABLE>
The Company has outstanding $230,000,000 4 1/4% Convertible Subordinated
Notes Due 2003 which are convertible into common stock of the Company, at any
time prior to maturity, at $36.65 per share. The securities are subordinated to
all present and future senior indebtedness. The Company, at its election on or
after November 1, 1996, amy redeem these Notes in whole or in part at 102.975
percent of the principal amount. The call premium percentage decreases,
beginning November 1, 1997, and each year thereafter until 2003 when these Notes
are redeemable at par value plus accrued interest.
The Company also has outstanding $100,000,000 7 1/4% Notes Due 2023. The
Company may not redeem any portion of these Notes prior to maturity. The
indenture governing these Notes contains certain restrictions as to the sale of
assets and incurrence of additional debt.
The Company has a credit agreement with certain banks which provides for
maximum unsecured borrowings of $100 million at variable rates. At December 31,
1994, the Company had outstanding $48 million against its line of credit. On
September 29, 1995, the Company borrowed $25 million under its credit agreement
and used the proceeds to acquire three Gulf of Mexico properties. On October
17, 1995 an additional $5 million was borrowed under the credit agreement and
the proceeds used to fund operations. Both the $25 million and $5 million loans
were repaid on December 1, 1995. The interest rate is a variable rate based on
the lowest of three interest rate options. The weighted average interest rate
on the borrowings during 1995 was 7 percent. There is a facility fee of
$187,500 per year. The agreement contains covenants including maintenance of
certain financial ratios, net worth requirements and restrictions of additional
borrowings. The credit agreement terminates on May 31, 1997.
During the next five years, no principal payments on long-term debt are
required except for the $48 million outstanding against the bank debt, which is
due May 31, 1997.
NOTE 4 - INCOME TAXES
The components of income from operations before income taxes for each year
are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
- ---------------------------------------------------------------
<S> <C> <C> <C>
Domestic $ 18,368 $12,148 $ 39,564
Foreign (10,370) (6,923) (18,905)
- ---------------------------------------------------------------
$ 7,998 $ 5,225 $ 20,659
- ---------------------------------------------------------------
</TABLE>
The income tax provisions relating to operations for each year consist of the
following:
<TABLE>
<CAPTION>
1995 1994 1993
- ------------------------------------------------------------------
<S> <C> <C> <C>
U.S. current $(9,309) $(10,462) $ 327
U.S. deferred 11,327 13,140 7,701
State current 65 231
State deferred 258 (31) 85
Foreign current 121
Foreign deferred 1,450 (588) (310)
- ------------------------------------------------------------------
$ 3,912 $ 2,059 $8,034
- ------------------------------------------------------------------
</TABLE>
The net current deferred tax asset in the following table is classified as
Other Current Assets (Liability) in the Consolidated Balance Sheet at December
31, 1995 and 1994. The tax effects of temporary differences which gave rise to
deferred tax assets and liabilities as of December 31 were:
<TABLE>
<CAPTION>
1995 1994
- -----------------------------------------------------------------------------
<S> <C> <C>
U.S. and State Current Deferred Tax Assets:
Accrued expenses $ (513) $ 743
Deferred income 525 (49)
Deferred hedge (2,281)
Minimum tax 1,460 3,655
Other 516 751
- -----------------------------------------------------------------------------
Net current deferred tax asset (liability) (293) 5,100
- -----------------------------------------------------------------------------
U.S. and State Non-current Deferred Tax Liabilities:
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments (71,789) (62,050)
Accrued expenses 2,824
Income tax accruals 1,287 690
Other (317) (442)
- -----------------------------------------------------------------------------
Net non-current deferred liability (67,995) (61,802)
- -----------------------------------------------------------------------------
U.S. and state net deferred tax liability (68,288) (56,702)
- -----------------------------------------------------------------------------
Foreign Deferred Tax Liabilities:
Property, plant and equipment of
foreign operations 12,836 7,532
Valuation allowance (14,286) (7,532)
- -----------------------------------------------------------------------------
Deferred tax liability (1,450)
- -----------------------------------------------------------------------------
Total deferred taxes $(69,738) $(56,702)
- -----------------------------------------------------------------------------
</TABLE>
A valuation allowance of $14.3 million and $7.5 million for 1995 and 1994,
respectively, related to the Company's foreign operations, was established for
the portion of the deferred tax assets which management believes is unlikely to
have a tax benefit realized.
<PAGE>
The following table details the difference between the federal statutory tax
rate and the effective tax rate for the years ended December 31:
<TABLE>
<CAPTION>
(AMOUNTS EXPRESSED IN PERCENTAGES) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory rate 35.0 35.0 35.0
Effect of:
One percent rate increase on prior
year temporary differences 5.0
Percentage depletion (1.4) (2.2) .6
State taxes 2.6 .1 1.1
Foreign taxes 12.8
Net operating loss carryback 7.9
Other, net (.1) (1.4) (2.8)
- --------------------------------------------------------------------------------
Effective rate 48.9 39.4 38.9
- --------------------------------------------------------------------------------
</TABLE>
NOTE 5 - COMMON STOCK AND STOCK OPTIONS
At December 31, 1995, there were 871,189 shares available for grant under the
Company's 1992 Stock Option and Restricted Stock Plan and its 1988 Non-Employee
Director Stock Option Plan.
Under the Company's 1992 Stock Option and Restricted Stock Plan, adopted in
January 1992, the Board of Directors may grant stock options and award
restricted stock. The Plan allows stock options to be issued at the market price
on the date of grant. The earliest the options may be exercised is over a three
year period at the rate of 33 1/3% each year commencing on the first anniversary
of the grant date. The options expire ten years from the grant date. The plan
covers a maximum of 2,000,000 shares of the Company's authorized but unissued
common stock. At December 31, 1995, the Company had reserved 1,887,174 shares of
its common stock for issuance under its 1992 stock option plan.
The Company's 1988 Non-Employee Director Stock Option Plan, adopted in July
1988, allows stock options to be issued at the market price on the date of
grant. The options may be exercised one year after issue and expire ten years
from the grant date. The Plan provides for the grant of options to purchase a
maximum of 250,000 shares of the Company's authorized but unissued common stock.
At December 31, 1995, the Company had reserved 151,500 shares of its common
stock for issuance under its 1988 stock option plan.
Stock options outstanding under the Plans mentioned above and two previously
terminated plans are presented for the periods indicated.
<TABLE>
<CAPTION>
NUMBER OPTION
OF SHARES PRICE RANGE
- --------------------------------------------------------------------------------
<S> <C> <C>
Outstanding December 31, 1992 1,284,948 $10.63-$17.47
- --------------------------------------------------------------------------------
Granted 271,224 $24.63-$24.88
Exercised (337,407) $10.63-$17.47
Cancelled (14,817) $10.88-$17.47
- --------------------------------------------------------------------------------
Outstanding December 31, 1993 1,203,948 $10.63-$24.88
- --------------------------------------------------------------------------------
Granted 303,243 $27.25-$30.00
Exercised (76,333) $10.63-$24.88
Cancelled (1,476) $13.75-$16.88
- --------------------------------------------------------------------------------
Outstanding December 31, 1994 1,429,382 $10.63-$30.00
- --------------------------------------------------------------------------------
Granted 357,663 $24.25-$25.50
Exercised (185,192) $10.63-$27.25
Cancelled (18,144) $16.88-$27.25
- --------------------------------------------------------------------------------
Outstanding December 31, 1995 1,583,709 $10.63-$30.00
- --------------------------------------------------------------------------------
Exercisable at December 31, 1995 981,620 $10.63-$30.00
- --------------------------------------------------------------------------------
</TABLE>
In October 1995, The Financial Accounting Standards Board issued SFAS No. 123
"Accounting for Stock-Based Compensation." The Company plans to adopt SFAS NO.
123 during 1996 by electing the additional disclosure in the footnotes to its
financial statements as opposed to recognition as compensation expense.
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory defined benefit pension plan covering
substantially all of its domestic employees. The benefits are based on an
employee's years of service and average earnings for the 60 consecutive calendar
months of highest compensation. The Company also has an unfunded restoration
plan to ensure payments of amounts for which employees are entitled under the
provisions of the pension plan, but which are subject to limitations imposed by
federal tax laws. The Company's funding policy has been to make annual
contributions equal to the actuarially computed liability to the extent such
amounts are deductible for income tax purposes. Plan assets consist principally
of equity securities and fixed income investments.
<PAGE>
The periodic pension expense included the following components for the years
ended December 31:
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost-benefits earned in the period $1,781 $1,814 $1,388
Interest cost on projected benefit obligation 3,298 2,876 2,611
Actual return on plan assets (8,611) 1,346 (4,411)
Net amortization and deferral 5,461 (4,200) 1,428
- --------------------------------------------------------------------------------
Net pension expense $1,929 $1,836 $1,016
- --------------------------------------------------------------------------------
</TABLE>
The funded status of the plans at December 31 was as follows:
<TABLE>
<CAPTION>
1995 1994
----------------- -----------------
FUNDED UNFUNDED FUNDED UNFUNDED
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Actuarial present value of:
Vested benefit obligation $27,445 $ 2,934 $25,037 $ 2,447
Accumulated benefit
obligation 31,009 3,069 27,307 2,620
- --------------------------------------------------------------------------------
Projected benefit obligation 42,946 5,055 35,468 3,890
Plan assets at fair value 42,070 35,810
- --------------------------------------------------------------------------------
Plan assets in excess of
(less than) projected
benefit obligation (876) (5,055) 342 (3,890)
Unrecognized net (gain) loss (4,711) 536 (4,527) (176)
Unrecognized net (asset)
liability at transition (2,152) 3,488 (2,367) 3,727
Unrecognized prior
service cost 2,325 155 2,242
- --------------------------------------------------------------------------------
Accrued pension cost $(5,414) $ (876) $(4,310) $ (339)
- --------------------------------------------------------------------------------
</TABLE>
The Company's assumptions as of December 31 in determining the pension cost
and liability for the three years were as follows:
<TABLE>
<CAPTION>
(AMOUNTS EXPRESSED IN PERCENTAGES) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 7.25 8.5 7.0
Rates of increase in compensation 4.50 6.0 5.0
Long-term rate of return on plan assets 8.50 8.5 8.5
</TABLE>
EMPLOYEE SAVINGS PLAN
The Company has an employee savings plan (ESP) which is a defined
contribution plan. Participation in the ESP is voluntary and all regular
employees of the Company are eligible to participate after one year of
employment. Subject to certain limitations, the Company may contribute up to 100
percent of the participant's contribution. Plan contributions of $895,000,
$775,000 and $755,000 for 1995, 1994 and 1993, respectively, were charged to
expense.
OTHER EMPLOYEE PLANS
The Company sponsors other plans for the benefit of its employees and
retirees. These plans include health care and life insurance benefits. The
accumulated postretirement benefit obligation of these plans was computed using
an assumed discount rate of 7.25, 8.5 and 7 percent in 1995, 1994 and 1993,
respectively. The health care cost trend rate was assumed to be 11 percent for
1995, declining by one percent for six successive years to 6 percent in 2000 and
2001, decreasing to 5.5 percent for 2002 and remaining at that rate thereafter.
If the health care cost trend rate was increased one percent for all
future years, the accumulated postretirement benefit obligation as of
December 31, 1995, would have increased approximately $270,000. The effect of
this change on the aggregate of service and interest cost for 1995 would have
been an increase of approximately $42,000.
Net postretirement benefit cost for the years ended December 31 includes the
following components:
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost-benefits earned in the period $140 $136 $ 91
Interest cost-accumulated benefit obligation 123 93 82
Net loss amortization 12 24
Cumulative catch up 1,003
- --------------------------------------------------------------------------------
Net postretirement benefit cost $275 $253 $1,176
- --------------------------------------------------------------------------------
</TABLE>
The plan's postretirement benefit obligation at December 31 was as follows:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees $ (173) $ (152)
Fully eligible active employees (363) (170)
Active employees, not fully eligible (1,471) (854)
- --------------------------------------------------------------------------------
Total participants (2,007) (1,176)
Plan assets
- --------------------------------------------------------------------------------
Funded status (2,007) (1,176)
Unrecognized net loss 656 35
- --------------------------------------------------------------------------------
Accrued postretirement benefit obligation $(1,351) $(1,141)
- --------------------------------------------------------------------------------
</TABLE>
<PAGE>
NOTE 7 - MARKETING SUBSIDIARIES
In June 1994, NGM began marketing the Company's natural gas as well as third-
party gas. NGM sells gas directly to end-users, gas marketers, industrial users,
interstate and intrastate gas pipelines, and local distribution companies. The
Company records all of NGM's sales as gathering, marketing and processing
revenues. All intercompany sales and expenses have been eliminated.
During 1995, NGM recorded $104.6 million in gathering, marketing and
processing revenues and $100.6 million in gathering, marketing and processing
expenses, generating a gross margin of $4 million for the year. The gross margin
was offset by administrative expenses of $1.6 million, resulting in pretax
income of $2.4 million for its second year of operation.
In 1994, NGM recorded $43.9 million in gathering, marketing and processing
revenues and $42.8 million in gathering, marketing and processing expenses,
generating a gross margin of $1.1 million for the year. The gross margin was
offset by administrative expenses of $1.2 million, resulting in a slight loss
for NGM's initial year of operation.
In May 1995, NTI began marketing a portion of the Company's oil as well as
third-party oil. The Company records all of NTI's sales as gathering, marketing
and processing revenues. All intercompany sales and expenses have been
eliminated.
During 1995, NTI recorded $8.1 million in gathering, marketing and processing
revenues and $7.3 million in gathering, marketing and processing expenses,
generating a gross margin of $791,000 for the year. The gross margin was offset
by administrative expenses of $52,000, resulting in pretax income of $739,000
for NTI's initial year of operation.
NOTE 8 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Other current assets at December 31 include the following:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------
<S> <C> <C>
Income tax receivable $9,329 $17,545
Deferred hedges (January 1996 hedges
closed in December 1995) 7,632
</TABLE>
Other current liabilities at December 31 include the following:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------
<S> <C> <C>
Gas imbalance liabilities $5,173 $2,101
</TABLE>
Oil and gas exploration expense included the following for the years ended
December 31:
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Dry hole expense $17,608 $35,275 $13,968
Undeveloped lease amortization 6,465 7,813 12,063
Abandoned assets 483 2,945 6,068
Seismic 8,358 8,254 5,199
</TABLE>
Listed below is the only purchaser who accounted for more than ten percent of
total oil and gas sales and royalties in the past three years.
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Clearinghouse * 16% 16%
</TABLE>
*Less than ten percent
NOTE 9 - IMPAIRMENT OF LONG-LIVED ASSETS
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of." The Company adopted SFAS No. 121 during the fourth quarter of
1995.
The assets impaired under SFAS No. 121 are oil and gas properties maintained
under the successful efforts method of accounting. The excess of the net book
value over the projected discounted future net revenue of the impaired
properties was charged to DD&A expense. The Company recognized a $59.5 million
SFAS No. 121 impairment for 1995. The Company impaired $3.2 million in Tunisia,
$4.1 million in Canada, $18.4 million onshore U.S., and $33.8 million in
offshore Gulf of Mexico properties.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Noble Affiliates, Inc.:
We have audited the accompanying consolidated balance sheet of Noble
Affiliates, Inc. (a Delaware corporation) and subsidiaries as of December 31,
1995 and 1994, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1995. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Noble Affiliates, Inc. and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
As explained in Note 9 to the financial statements, in 1995 the Company
adopted Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
Oklahoma City, Oklahoma ARTHUR ANDERSEN LLP
January 26, 1996
<PAGE>
NOTE 10 - SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
The following reserve schedules were developed by the Company's reserve
engineers and set forth the changes in estimated quantities of proved oil and
gas reserves of the Company during each of the three years presented, and the
proved developed oil and gas reserves as of the beginning of each year.
<TABLE>
<CAPTION>
NATURAL GAS & CASINGHEAD GAS (MMCF) CRUDE OIL & CONDENSATE
(BARRELS IN THOUSANDS)
- ----------------------------------------------------------------------------------------------------------------------------------
UNITED OTHER UNITED OTHER
Proved developed and undeveloped reserves: STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PROVED RESERVES AS OF DECEMBER 31, 1992 344,366 25,449 2,408 372,223 39,958 2,342 5,080 47,380
- ----------------------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates (5,811) 809 (5,002) (2,374) 168 (277) (2,483)
Extensions, discoveries and other additions 62,479 2,131 64,610 7,285 1,410 8,695
Production (71,310) (3,829) (75,139) (6,064) (347) (950) (7,361)
Sale of minerals in place (6,903) (20) (6,923) (389) (23) (412)
Purchase of minerals in place 341,578 183 341,761 27,107 29 27,136
- ----------------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF DECEMBER 31, 1993 664,399 24,723 2,408 691,530 65,523 3,579 3,853 72,955
- ----------------------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates 15,409 2,418 17,827 (1,052) 161 1,550 659
Extensions, discoveries and other additions 148,008 6,773 154,781 8,160 712 1,139 10,011
Production (84,504) (3,225) (87,729) (7,434) (446) (791) (8,671)
Sale of minerals in place (854) (167) (1,021) (276) (19) (295)
Purchase of minerals in place 1,787 1,775 3,562 615 253 868
- ----------------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF DECEMBER 31, 1994 744,245 32,297 2,408 778,950 65,536 4,240 5,751 75,527
- ----------------------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates (35,728) (4,776) (40,504) 247 (818) 301 (270)
Extensions, discoveries and other additions 143,589 6,558 150,147 12,270 311 3,347 15,928
Production (94,038) (2,946) (96,984) (8,175) (421) (984) (9,580)
Sale of minerals in place (2,424) (3,489) (5,913) (115) (6) (121)
Purchase of minerals in place 62,657 1,986 64,643 1,144 570 810 2,524
- ----------------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF DECEMBER 31, 1995 818,301 29,630 2,408 850,339 70,907 3,876 9,225 84,008
- ----------------------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED RESERVES:
January 1, 1993 344,366 24,504 2,408 371,278 36,938 1,884 5,080 43,902
January 1, 1994 570,462 24,723 2,408 597,593 64,284 3,032 3,853 71,169
January 1, 1995 658,228 32,297 2,408 692,933 63,013 3,693 4,612 71,318
January 1, 1996 750,753 29,628 2,408 782,789 67,368 3,763 7,904 79,035
</TABLE>
PROVED RESERVES
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED DEVELOPED RESERVES
Proved developed reserves are proved reserves which are expected to be
recovered through existing wells with existing equipment and operating methods.
<PAGE>
COSTS INCURRED IN OIL AND GAS ACTIVITIES
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities during the year are shown below. Amounts
are presented in accordance with SFAS No. 19, and may not agree with amounts
determined using traditional industry definitions.
<TABLE>
<CAPTION>
1995
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Property acquisition costs:
Proved $ 36,728 $ 3,182 $ 3,750 $ 43,660
Unproved 8,209 1,096 9,305
- --------------------------------------------------------------------------------
Total $ 44,937 $ 4,278 $ 3,750 $ 52,965
- --------------------------------------------------------------------------------
Exploration costs $ 39,008 $ 2,811 $ 8,775 $ 50,594
- --------------------------------------------------------------------------------
Development costs $159,405 $ 3,096 $ (115) $162,386
- --------------------------------------------------------------------------------
<CAPTION>
1994
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Property acquisition costs:
Proved $ 3,742 $ 2,375 $ $ 6,117
Unproved 8,695 1,773 10,468
- --------------------------------------------------------------------------------
Total $ 12,437 $ 4,148 $ $ 16,585
- --------------------------------------------------------------------------------
Exploration costs $ 48,151 $ 7,293 $ 7,363 $ 62,807
- --------------------------------------------------------------------------------
Development costs $105,993 $ 2,871 $ 1,474 $110,338
- --------------------------------------------------------------------------------
<CAPTION>
1993
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Property acquisitions costs:
Proved $418,087 $ 364 $ $418,451
Unproved 2,537 1,902 4,439
- --------------------------------------------------------------------------------
Total $420,624 $ 2,266 $ $422,890
- --------------------------------------------------------------------------------
Exploration costs $ 23,392 $ 4,708 $ 5,449 $ 33,549
- --------------------------------------------------------------------------------
Development costs $ 53,650 $ 4,192 $ 730 $ 58,572
- --------------------------------------------------------------------------------
</TABLE>
AGGREGATE CAPITALIZED COSTS
Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A as of the end of the year are shown
below.
<TABLE>
<CAPTION>
1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
UNITED OTHER UNITED OTHER
STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Unproved oil and gas properties $ 31,124 $ 5,784 $ $ 36,908 $ 34,254 $ 7,842 $ 3,274 $ 45,370
Proved oil and gas properties 1,558,009 32,823 30,416 1,621,248 1,448,412 42,315 24,295 1,515,022
- ----------------------------------------------------------------------------------------------------------------------------------
1,589,133 38,607 30,416 1,658,156 1,482,666 50,157 27,569 1,560,392
Accumulated DD&A (794,622) (18,649) (13,058) (826,329) (722,701) (23,017) (10,665) (756,383)
- ----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 794,511 $ 19,958 $ 17,358 $ 831,827 $ 759,965 $ 27,140 $ 16,904 $ 804,009
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
OIL AND GAS OPERATIONS
Aggregate results of operations in connection with the Company's oil and
gas producing activities are shown below.
<TABLE>
<CAPTION>
1995
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $301,710 $ 9,461 $ 16,963 $328,134
Production costs 74,911 3,863 3,610 82,384
Exploration expenses 40,971 2,793 9,469 53,233
DD&A and valuation provision 191,227 7,414 5,701 204,342*
- --------------------------------------------------------------------------------
Income (loss) (5,399) (4,609) (1,817) (11,825)
Income tax expense (benefit) (2,046) (2,901) 605 (4,342)
- --------------------------------------------------------------------------------
Results of operations
From producing
Activities (excluding
corporate overhead
and interest costs) $ (3,353) $ (1,708) $ (2,422) $ (7,483)
- --------------------------------------------------------------------------------
<CAPTION>
1994
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $277,467 $ 15,448 $ 13,254 $306,169
Production costs 68,340 4,072 3,128 75,540
Exploration expenses 49,991 8,874 9,373 68,238
DD&A and valuation provision 125,880 4,153 2,373 132,406
- --------------------------------------------------------------------------------
Income (loss) 33,256 (1,651) (1,620) 29,985
Income tax expense (benefit) 11,503 (1,039) 1,006 11,470
- --------------------------------------------------------------------------------
Results of operations
From producing
Activities (excluding
corporate overhead
and interest costs) $ 21,753 $ (612) $ (2,626) $ 18,515
- --------------------------------------------------------------------------------
<CAPTION>
1993
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $250,636 $ 12,812 $ 14,556 $278,004
Production costs 66,507 4,150 6,084 76,741
Exploration expenses 28,927 5,662 8,333 42,922
DD&A and valuation provision 101,609 3,549 11,396 116,554
- --------------------------------------------------------------------------------
Income (loss) 53,593 (549) (11,257) 41,787
Income tax expense (benefit) 19,345 (776) (3,559) 15,010
- --------------------------------------------------------------------------------
Results of operations
From producing
Activities (excluding
corporate overhead
and interest costs) $ 34,248 $ 227 $ (7,698) $ 26,777
- --------------------------------------------------------------------------------
</TABLE>
*Includes $59.5 million of additional DD&A as a result of adoption of
SFAS No. 121.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
required by Financial Accounting Standards Board's Statement of Financial
Accounting Standards No. 69. The Standard requires the use of a 10 percent
discount rate. This information is not the fair market value nor does it
represent the expected present value of future cash flows of the Company's
proved oil and gas reserves.
<TABLE>
<CAPTION>
1995
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Future cash inflows $3,610 $91 $186 $3,887
Future production and
development costs 1,055 37 21 1,113
Future income tax expenses 709 15 46 770
- --------------------------------------------------------------------------------
Future net cash flows 1,846 39 119 2,004
10% annual discount for
estimated timing of
cash flows 673 14 43 730
- --------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $1,173 $25 $76 $1,274
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<CAPTION>
1994
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Future cash inflows $2,439 $120 $104 $2,663
Future production and
development costs 870 44 18 932
Future income tax expenses 423 21 23 467
- --------------------------------------------------------------------------------
Future net cash flows 1,146 55 63 1,264
10% annual discount for
estimated timing of
cash flows 479 23 26 528
- --------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 667 $ 32 $37 $ 736
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<CAPTION>
1993
- --------------------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Future cash inflows $2,635 $102 $55 $2,792
Future production and
development costs 869 47 17 933
Future income tax expenses 481 15 10 506
- --------------------------------------------------------------------------------
Future net cash flows 1,285 40 28 1,353
10% annual discount for
estimated timing of
cash flows 656 13 9 678
- --------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 629 $ 27 $19 $ 675
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
</TABLE>
<PAGE>
Future cash inflows are computed by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves, with consideration given to the effect of existing trading and hedging
contracts if any. The year-end weighted average oil price utilized in the
computation of future cash inflows was approximately $17.64 per barrel.
West Texas intermediate crude oil price in February 1996 was flat with the
price at year-end 1995. The Company estimates that a $1.00 per barrel change in
the average oil price from the year-end price would change discounted future net
cash flows before income taxes by approximately $49 million.
The year-end weighted average gas price utilized in the computation of future
cash inflows was approximately $3.06 per MCF. Natural gas index prices at Henry
Hub have decreased approximately $1.00 per MCF during February 1996 compared
with the year-end index. The Company estimates that a $.10 per MCF change in the
average gas price from the year-end price would change discounted future net
cash flows before income taxes by approximately $52 million.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates to the future pretax net cash flows relating to the
Company's proved oil and gas reserves, less the tax bases of the properties
involved. The future income tax expenses give effect to tax credits and
allowances, but do not reflect the impact of general and administrative cost and
exploration expenses of ongoing operations relating to the Company's proved oil
and gas reserves.
At December 31, 1995, the Company had estimated gas imbalance receivables of
$12.3 million and estimated liabilities of $11.4 million; at year-end 1994,
$11.7 million in receivables and $10.5 million in liabilities; and at year-end
1993, $12.9 million in receivables and $7.6 million in liabilities. Neither the
gas imbalance receivables nor liabilities have been included in the standardized
measure of discounted future net cash flows for the three years ended
December 31, 1995.
Principal changes in the aggregate standardized measure of discounted future
net cash flows attributable to the Company's proved oil and gas reserves at year
end are shown below.
<TABLE>
<CAPTION>
(IN MILLIONS OF DOLLARS) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Standardized measure of discounted
future net cash flows at the beginning
of the year $ 736 $675 $488
Extensions, discoveries and improved
recovery, less related costs 378 160 89
Revisions of previous quantity estimates (53) 18 (19)
Changes in estimated future
development costs (29) (31) (23)
Purchases/sales of minerals in place 116 3 397
Net changes in prices and production costs 378 (90) (40)
Accretion of discount 103 95 66
Sales of oil and gas produced, net of
Production costs (241) (228) (200)
Development costs incurred during
The period 67 44 8
Net change in income taxes (216) (17) (102)
Change in timing of estimated future
production, and other 35 107 11
- --------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the end
of the year $1,274 $736 $675
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
</TABLE>
NOTE 11 - INTERIM FINANCIAL INFORMATION
(UNAUDITED)
Interim financial information for the years ended
December 31, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
Quarter Ended
- --------------------------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31,
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1995
Revenues $91,854 $107,130 $110,290 $177,744
Gross profit
from operations $ 5,266 $ 10,186 $ 9,013 $ 2,277
Net income (loss) $ 440 $ 3,357 $ 2,729 $ (2,440)
Net income (loss) per share $ .01 $ .07 $ .05 $ (.05)
1994
Revenues $83,541 $ 92,032 $ 97,441 $ 85,375
Gross profit (loss)
from operations $16,351 $ 10,494 $ 3,877 $(13,451)
Net income (loss) $ 8,417 $ 4,377 $ 2,051 $(11,679)
Net income (loss) per share $ .17 $ .09 $ .04 $ (.23)
</TABLE>
During the fourth quarter of 1995, the Company recognized two non-recurring
items. In November, $39 million was recorded as income from the settlement of a
bankruptcy claim against Columbia Gas Transmission Corporation. In December, the
Company recorded a pretax charge of $59.5 million relating to the adoption of
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long
Lived Assets to Be Disposed Of."
During the fourth quarter of 1995 and 1994, DD&A expense decreased $3.1
million and increased $3.1 million, respectively, relating to the cumulative
effect of oil and gas reserve revisions on the DD&A provision for the preceding
three quarters.
<PAGE>
CORPORATE INFORMATION
TRANSFER AGENT AND REGISTRAR
LIBERTY BANK AND TRUST COMPANY OF OKLAHOMA CITY, N. A.
P. O. BOX 25848
OKLAHOMA CITY, OKLAHOMA 73125
INDEPENDENT ACCOUNTANTS
ARTHUR ANDERSEN LLP
OKLAHOMA CITY, OKLAHOMA
COMMON STOCK LISTED
NEW YORK STOCK EXCHANGE
SYMBOL - NBL
SHAREHOLDERS' PROFILE
December 31, 1995
<TABLE>
<CAPTION>
SHARES SHAREHOLDERS
OUTSTANDING OF RECORD
- -------------------------------------------------------------------
<S> <C> <C>
Individuals 750,848 1,145
Joint accounts 104,073 252
Fiduciaries 223,585 321
Institutions 6,942,285 48
Brokers 101,500 3
Nominees 42,061,895 4
Foreign 13,561 17
- -------------------------------------------------------------------
Total 50,197,747 1,790
- -------------------------------------------------------------------
- -------------------------------------------------------------------
</TABLE>
ANNUAL MEETING
The Annual Meeting of Shareholders of Noble Affiliates, Inc. will be held on
Tuesday, April 23, 1996, at 10:00 a.m. at the Charles B. Goddard Center located
at "D" Street and First Avenue S.W. in Ardmore, Oklahoma. All shareholders are
cordially invited to attend.
FORM 10-K
A copy of Form 10-K, as filed with the Securities and Exchange Commission, is
available upon request by writing to Vice President - Finance and Treasurer,
Noble Affiliates, Inc., P.O. Box 1967, Ardmore, Oklahoma 73402.
DIVIDENDS AND STOCK PRICES BY QUARTERS
<TABLE>
<CAPTION>
QUARTER ENDED YEAR
- ------------------------------------------------------------------------- END
(DOLLARS) 3/31 6/30 9/30 12/31 TOTAL
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Dividends
1995 .04 .04 .04 .04 .16
1994 .04 .04 .04 .04 .16
Low-High
1995 21 1/4-27 1/2 25 1/2-29 23 5/8-29 1/8 22 5/8-30 1/2
1994 23 3/8-28 3/4 22 1/2-32 1/4 25 1/4-30 7/8 22 1/2-30 3/8
</TABLE>
GLOSSARY
BBL Barrel
BCF Billion Cubic Feet
BOE Barrel of Oil Equivalent
LPG Liquid Petroleum Gas
MCF Thousand Cubic Feet
MMBBL Million Barrels
MMBTU Million British Thermal Units
MMCF Million Cubic Feet
<PAGE>
APPENDIX I
The following describes graphs which were listed in the body of the
Management's Discussion and Analysis on pages 15 through 20 of the Registrants
1995 annual report.
Page 15 - Costs Incurred For Acquisitions, Exploration and
Development for three years
1993: $515 million
1994: $190 million
1995: $266 million
Average Finding Cost Per BOE for three years
1993: $5.14
1994: $4.64
1995: $5.64
3 Year Average: $5.16
Page 16 - Gas Reserves Added for three years
1993: 401.4 BCF'S
1994: 176.2 BCF'S
1995: 174.3 BCF'S
Oil Reserves Added for three years
1993: 33.3 million barrels
1994: 11.5 million barrels
1995: 18.2 million barrels
Net Income for three years
1993: $12.6 million
1994: $3.2 million
1995: $4.1 million
Page 17 - Gas Revenues for three years
1993: $159.2 million - $2.10 Average price per mcf
1994: $174.5 million - $1.97 Average price per mcf
1995: $167.4 million - $1.72 Average price per mcf
Oil Revenues for three years
1993: $111.3 million - $15.91 Average price per barrel
1994: $122.9 million - $14.90 Average price per barrel
1995: $153.5 million - $16.78 Average price per barrel
Page 18 - DD&A Expense Per BOE of
Production for three years
1993: $5.37 per barrel
1994: $5.46 per barrel
1995: $7.75 per barrel ($5.46 without effect of FASB No. 121)
Page 19 - SG&A Expense Per BOE of
Production for three years
1993: $1.59 per barrel
1994: $1.56 per barrel
1995: $1.41 per barrel
Page 20 - Average Production and Lifting
Cost Per BOE
1993: $3.76
1994: $3.20
1995: $3.15
<PAGE>
EXHIBIT 21
SUBSIDIARIES OF NOBLE AFFILIATES, INC.
The following table sets forth the subsidiaries of Noble
Affiliates, Inc. as of March 15, 1996.
State of Jurisdiction
Subsidiary or Organization
---------- ---------------------
Samedan Oil Corporation 1/ Delaware
Noble Gas Marketing, Inc. 1/ Delaware
Noble Trading, Inc. 1/ Delaware
NPM, Inc. 1/ Delaware
Noble Gas Pipeline, Inc. 2/ Delaware
Samedan Oil of Canada, Inc. 3/ Delaware
Samedan of North Africa, Inc. 3/ Delaware
Samedan Oil of Indonesia, Inc. 3/ Delaware
Samedan Pipe Line Corporation 3/ Delaware
Samedan Royalty Corporation 3/ Delaware
Samedan of Tunisia, Inc. 3/ Delaware
Samedan - NEEI Exploration Company 4/ Oklahoma
Samedan LPG 5/ Cayman Islands, British West Indies
- -------------
1/ 100% owned by Noble Affiliates, Inc.
2/ 100% owned by Noble Gas Marketing, Inc.
3/ 100% owned by Samedan Oil Corporation.
4/ 50% general partnership interest owned by
Samedan Oil Corporation.
5/ 100% owned by Samedan of North Africa, Inc.
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated January 26, 1996, included on page 33 of the 1995 Annual
Report to Shareholders and incorporated by reference in this Form 10-K, into
the previously filed Registration Statements on Form S-8 (File Nos. 2-64600,
2-81590, 33-32692, 2-66654 and 33-54084).
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
March 25, 1996
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<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
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0
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