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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
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)
(580) 223-4110
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange on
Title of Each Class Which Registered
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Common Stock, $3.33-1/3 par value New York Stock Exchange, Inc.
Preferred Stock Purchase Rights 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.
---
Aggregate market value of Common Stock held by nonaffiliates as of
February 17, 1998: $1,918,000,000.
Number of shares of Common Stock outstanding as of February 17, 1998:
56,958,238.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 1998
Annual Meeting of Stockholders to be held on April 28, 1998, which will be filed
with the Securities and Exchange Commission within 120 days after December 31,
1997, are incorporated by reference into Part III.
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TABLE OF CONTENTS
PART I.
Item 1. Business.................................................................................... 1
General..................................................................................... 1
Oil and Gas................................................................................. 1
Exploration Activities.................................................................. 2
Production Activities .................................................................. 4
Acquisitions of Unproved Properties..................................................... 5
Marketing............................................................................... 5
Regulations and Risks................................................................... 6
Competition............................................................................. 7
Employees................................................................................... 7
Item 2. Properties.................................................................................. 8
Offices..................................................................................... 8
Oil and Gas................................................................................. 8
Item 3. Legal Proceedings........................................................................... 15
Item 4. Submission of Matters to a Vote of Security Holders......................................... 16
Executive Officers of the Registrant........................................................ 16
PART II.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................... 18
Item 6. Selected Financial Data..................................................................... 19
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.................................. 27
Item 8. Financial Statements and Supplementary Data................................................. 28
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ 51
PART III.
Item 10. Directors and Executive Officers of the Registrant.......................................... 52
Item 11. Executive Compensation...................................................................... 52
Item 12. Security Ownership of Certain Beneficial Owners and Management.............................. 52
Item 13. Certain Relationships and Related Transactions.............................................. 52
PART IV.
Item 14. Financial Statement Schedules, Exhibits and Reports on Form 8-K............................. 53
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PART I
ITEM 1. BUSINESS.
Part I and Part II of this Annual Report on Form 10-K include
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements
other than statements of historical facts included in this Annual Report on Form
10-K and the documents incorporated herein by reference regarding the Company's
estimates of oil and gas reserves and the future net cash flows attributable
thereto, anticipated capital expenditures, business strategy, plans and
objectives of management of the Company for future operations and industry
conditions, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
can give no assurance that such expectations will prove to have been correct.
Important factors that could cause actual results to differ materially from the
Company's expectations ("Cautionary Statements") include without limitation
future production levels, future prices and demand for oil and gas, results of
future exploration and development activities, future operating and development
costs, the effect of existing and future laws and governmental regulations
(including those pertaining to the environment) and the political and economic
climate of the United States and the foreign countries in which the Company
operates from time to time, as discussed in this Annual Report on Form 10-K and
the other documents of the Company filed with the Securities and Exchange
Commission. All subsequent written and oral forward-looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.
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, "Samedan" refers to Samedan Oil Corporation and its
subsidiaries, "EDC" refers to Energy Development Corporation and its
subsidiaries, "NGM" refers to Noble Gas Marketing, Inc. and its subsidiary, and
"NTI" refers to Noble Trading, Inc. Samedan's subsidiaries include EDC. 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"), billions of cubic feet ("BCF"), trillions of cubic feet ("TCF"),
million British Thermal Units ("MMBTU"); or barrel of oil equivalent ("BOE")
converting gas to oil at six thousand cubic feet of gas to one barrel of oil.
OIL AND GAS
The Company's wholly owned subsidiary, Samedan, has been engaged in the
exploration, production and marketing of oil and gas since 1932. Samedan has
exploration, exploitation and production operations in nine prominent areas:
four domestic areas and five international areas. The domestic areas consist of:
offshore in the Gulf of Mexico, the Gulf Coast (Texas and Louisiana), the Mid
Continent (Oklahoma and Southern Kansas), and the Rocky Mountain division
(Colorado, Montana, North Dakota, Wyoming and California). The international
areas of operations include Argentina, China, Ecuador, Equatorial Guinea and the
U.K. Sector of the North Sea. For more information regarding Samedan's oil and
gas properties, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
The Company's wholly owned, indirect subsidiary, EDC, was acquired on
July 31, 1996, when Samedan purchased all of the outstanding common stock of
EDC, previously a wholly owned, indirect subsidiary of Public Services
Enterprise Group Incorporated. The consolidated financial statements of the
Registrant (Item 8. of this Form 10-K) include EDC from and after July 31, 1996,
unless otherwise indicated.
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During 1997, the Registrant sold its Canadian operations. The
consolidated financial statements of the Registrant (Item 8. of this Form 10-K)
include the Canadian operations throughout the year. There will be no Canadian
operations in 1998.
The Company's wholly owned subsidiary, 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" of this Form 10-K.
The Company's wholly owned subsidiary, 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" of this Form 10-K.
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 on properties for
which it acquired such exploration rights.
Gulf of Mexico. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties in the Gulf of Mexico
(offshore Texas and Louisiana) since 1968. Generally, properties in the Gulf of
Mexico are characterized by prolific reservoirs with high production rates,
which therefore tend to deplete more rapidly than the Company's onshore
properties. The Company's current production in the Gulf of Mexico is derived
from 282 wells operated by Samedan and 525 wells operated by others. During the
past 29 years, Samedan has drilled or participated in the drilling of 833 gross
wells in the Gulf of Mexico. At December 31, 1997, the Company held offshore
federal leases covering 908,261 gross undeveloped acres in the Gulf of Mexico,
with expiration dates ranging from 1998 to 2007, on which the Company currently
intends to conduct future exploration activities.
Gulf Coast. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties on the Gulf Coast
(onshore Louisiana and Texas) since the 1930's. The Company's current production
in the Gulf Coast areas is derived from 428 wells operated by Samedan and 2,391
wells operated by others. Properties in the Gulf Coast area are characterized by
gas reservoirs with strong production rates and oil fields with primary and
secondary recovery operations which tend to deplete more gradually than the
Company's offshore properties. At December 31, 1997, the Company held 245,260
gross undeveloped acres in the Gulf Coast area on which the Company currently
intends to conduct future exploration activities.
Mid Continent. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties in the Mid Continent
region (Oklahoma and Southern Kansas) since 1932. The Company's current oil and
gas production in the Mid Continent is derived from 435 wells operated by
Samedan and 1,198 wells operated by others. Reservoirs in the Mid Continent
region tend to be characterized by stable oil and gas production from primary
and secondary recovery operations. These reservoirs tend to produce for longer
periods compared to the Company's offshore properties. At December 31, 1997, the
Company held 76,443 gross undeveloped acres in the Mid Continent area on which
the Company currently intends to conduct future exploration activities.
Rocky Mountain. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties in the Rocky Mountain
division (Colorado, Montana, North Dakota, Wyoming and California) since 1960.
The Company's current production in the Rocky Mountain division is derived from
945 wells operated by Samedan and 786 wells operated by others. Reservoirs in
the Rocky Mountain division are primarily characterized by oil and gas
production from primary recovery, secondary recovery and horizontally drilled
wells. The Rocky Mountain division has two unitized gas fields with an estimated
reserve life of 50 years. At December 31, 1997, the Company held 252,857 gross
undeveloped acres in the Rocky Mountain division on which it currently intends
to conduct future exploration activities.
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Argentina. Samedan, through its subsidiary EDC, has been actively
engaged in exploration, exploitation and development of oil and gas properties
in Argentina since acquiring EDC in 1996. The Company's properties are located
in southern Argentina in the El Tordillo Field, which is characterized by
secondary recovery oil production from a 10,000 acre reservoir. There appear to
be other exploitation opportunities within the field which the Company intends
to pursue in future programs. At December 31, 1997, the Company held 28,988
gross developed acres and 85,760 gross undeveloped acres in Argentina, with an
expiration date of 2016, on which the Company currently intends to conduct
future exploration activities.
China. Samedan, through its subsidiary EDC, has been actively engaged
in exploration and development of oil and gas properties in China since
acquiring EDC in 1996. The Company has four concessions in Bo Hai Bay, offshore
China. The Company was approved to operate two of the concessions by the Chinese
government in 1997. These concessions, Cheng Dao Xi and Cheng Zi Kou, are
contiguous and adjoin non-owned production in the southern portion of Bo Hai
Bay. The other two concessions, Laopu and Getuo, are located in the northern
portion of Bo Hai Bay. At December 31, 1997, the Company held 316,676 gross
undeveloped acres in China, on which the Company currently intends to conduct
future exploration activities.
Ecuador. Samedan, through its subsidiary EDC, has been actively engaged
in exploration and development of oil and gas properties in Ecuador since
acquiring EDC in 1996. The Company's presence in Ecuador is primarily in the
Amistad gas field (Offshore Ecuador) which was discovered in 1970. The
concession, which covers 864,126 gross acres and encompasses the Amistad field,
was awarded to EDC in 1996 by the Ecuadorian government.
Equatorial Guinea. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties Offshore Equatorial
Guinea (West Africa) since 1990. The primary Offshore Equatorial Guinea
production is from the Alba field. The field produces approximately 2,300 net
BBLS per day of condensate. The field also has a sizable gas reserve which will
be utilized as feedstock by the Company's methanol plant (see Item 2. of this
Form 10-K) that is currently in the preliminary stages of development. The plant
will be capable of producing 2,500 metric tons of methanol per day which is
equivalent to approximately 20,000 BBLS per day. Based on reserve estimates, the
Alba field can deliver gas sufficient for the plant to operate for 30 years. At
December 31, 1997, the Company held 26,651 gross developed acres and 284,000
gross undeveloped acres Offshore Equatorial Guinea, on which the Company
currently intends to conduct future exploration activities.
U.K. Sector of the North Sea. Samedan, through its subsidiary Brabant
Petroleum Limited ("Brabant"), has been actively engaged in exploration,
development and production of oil and gas properties in the U.K. Sector of the
North Sea since acquiring EDC in 1996. The Company's current production in the
U.K. Sector of the North Sea is derived from seven non-operated fields, of which
three are oil fields in the northern portion of the North Sea and four are gas
fields in the southern gas basin. The seven fields comprise a total of 116
producing wells. The Company's total average daily production from these
interests for 1997 was 2,400 BBLS of oil per day and 14,000 MCF of gas per day.
When acquired in July 1996, the Brabant interests were producing 8.7
MMCF of gas per day. At year end 1997, production had increased by 200 percent
to 26.1 MMCF per day and proven gas reserves had increased 6.6 percent to 47.3
BCF. Oil reserves at the end of 1997 were seven million BBLS. Key oil fields are
Buchan, Claymore and Forties. Key gas fields are Guinevere, Lancelot, Pickerill
and Windermere.
At December 31, 1997, the Company held 125,107 gross developed acres
and 533,816 gross undeveloped acres, with expiration dates ranging from 1999 to
2020, on which the Company intends to conduct future exploration activities.
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Production Activities
Operated Property Statistics. The percentage of oil and gas wells
operated and the percentage of sales volume from operated properties are shown
in the following table as of December 31:
1997 1996 1995
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(In percentages) Oil Gas Oil Gas Oil Gas
- ----------------------------------------------------------------------------------------------------------
Operated well count basis 15.1 60.8 22.4 57.4 19.1 56.8
Operated sales volume basis 48.8 63.5 56.6 68.3 54.5 64.6
Net Production. The following table sets forth Samedan's net production
including royalty and working interest of oil and natural gas, for the three
years ended December 31:
1997 1996 1995
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Oil Production
(million BBLS) 14.0 12.6 9.3
Gas Production
(BCF) 206.4 171.8 99.4
Oil and Gas Equivalents. The following table sets forth Samedan's net
production stated in oil and gas equivalents, for the three years ended December
31:
1997 1996 1995
- -----------------------------------------------------------------------------------------------------
Total Oil Equivalents
(million BBLS) 48.4 41.3 25.9
Total Gas Equivalents
(BCF) 290.4 247.6 155.5
Oil and Gas Wells. The number of productive oil and gas wells in which
Samedan held an interest as of December 31, 1997, 1996 and 1995 were as follows:
1997(1)(2)(3) 1996(1)(3) 1995(1)(3)
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Gross Net Gross Net Gross Net
OIL WELLS
United States - Onshore 4,614.5 881.4 4,607.0 860.8 3,554.5 796.0
United States - Offshore 327.0 140.3 343.0 151.1 256.5 110.9
International 549.0 58.5 629.0 91.8 126.0 41.9
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Total 5,490.5 1,080.2 5,579.0 1,103.7 3,937.0 948.8
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GAS WELLS
United States - Onshore 1,568.5 920.9 1,476.0 847.2 1,346.5 765.6
United States - Offshore 480.0 176.6 530.0 186.9 432.5 166.0
International 25.0 1.9 89.0 32.6 74.0 18.9
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Total 2,073.5 1,099.4 2,095.0 1,066.7 1,853.0 950.5
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(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) The reduction in gross international wells from December 31, 1996 to
December 31, 1997 was a result of the sale of the Company's Canadian oil
and gas operations during 1997.
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(3) One or more completions in the same bore hole is counted as one well in
the table above. The following table summarizes multiple completions and
non-producing wells as of December 31 for the years shown. Included in
wells not producing are wells awaiting additional action, pipeline
connections or shut-in for various reasons.
1997 1996 1995
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Gross Net Gross Net Gross Net
- -------------------------------------------------------------------------------------------------
MULTIPLE COMPLETIONS
Oil 24.5 18.1 21.0 14.4 28.0 18.2
Gas 48.5 21.6 47.0 23.6 46.0 19.4
NOT PRODUCING (SHUT-IN)
Oil 1,017.0 127.3 1,086.0 136.7 824.0 131.8
Gas 79.5 50.1 63.5 32.0 81.0 42.7
Samedan spent approximately $3.9 million in 1997 on the purchase of
producing oil and gas properties. Approximately $687 million of the EDC purchase
price was allocated to producing properties in 1996, and $43.7 million was spent
to purchase producing properties in 1995.
Acquisitions of Unproved Properties
During 1997, Samedan spent approximately $19.8 million on acquisitions
of unproved properties. These properties were acquired primarily through
domestic onshore lease acquisitions, various offshore lease sales and
international concession negotiations.
Marketing
NGM seeks opportunities to enhance the value of the Company's gas by
marketing directly to end users and accumulating gas to be sold to gas marketers
and pipelines. During 1997, approximately 47 percent of NGM's total sales were
to end users. 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 Pipeline, Inc., engages in the installation, purchase and
operation of gas gathering systems.
Samedan and EDC have gas sales contracts with NGM, whereby Samedan and
EDC are paid an index price for all gas sold to NGM. Sales, including hedging
transactions, are recorded as gathering, marketing and processing revenues. NGM
records as cost of sales in gathering, marketing and processing costs, the
amount paid to Samedan, EDC and third parties. All intercompany sales and
expenses are eliminated in the Company's consolidated financial statements.
Oil produced by the Company is sold to purchasers in the United States
and 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. NTI markets 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 and
records cost of sales in gathering, marketing and processing costs. All
intercompany sales and expenses are eliminated in the Company's consolidated
financial statements.
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 oil price decreased from $18.28 per BBL in 1996 to $17.86 per BBL in
1997. Due to the volatility of oil and gas prices, the Company, from time to
time, has used hedging and may do so in the future as a means of controlling its
exposure to price
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changes. The Company's average oil price reflected a reduction of $.19 per BBL
in 1997 and $2.35 per BBL in 1996, from hedging oil production.
Substantial competition in the natural gas marketplace continued in
1997. 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 increased from $2.17 per MCF in 1996 to $2.48
per MCF in 1997. Due to the volatility of oil and gas prices, the Company, from
time to time, has used hedging and may do so in the future as a means of
controlling its exposure to price changes. The Company's average gas price for
1997 and 1996 reflected a reduction of $.12 and $.33 per MCF, respectively, from
hedging gas production.
The largest single non-affiliated purchaser of the Company's oil in
1997 accounted for approximately 25 percent of its oil sales, and the five
largest purchasers accounted for approximately 63 percent of total oil sales.
The largest single non-affiliated purchaser of the Company's gas in 1997
accounted for approximately two percent of its gas sales, and the five largest
purchasers accounted for approximately six percent of total gas sales. The
Company does not believe that its loss of a major oil or gas purchaser would
have a material effect on the Company.
Regulations 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 the Company's
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 were eliminated over
a transition period which ended on January 1, 1993.
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,
risk 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
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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 and 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 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 and proximity of pipelines and
other transportation facilities, regulation by state and federal authorities and
the costs of complying with applicable environmental regulations.
EMPLOYEES
During the year, the total number of employees of the Company increased
nine percent from 563 at December 31, 1996, to 614 at December 31, 1997.
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ITEM 2. PROPERTIES.
OFFICES
The principal executive office of the Company is located at 110 West
Broadway, Ardmore, Oklahoma 73401. The principal office of Samedan is in
Ardmore, Oklahoma. Samedan also maintains offices in Oklahoma City, Houston,
Denver, United Kingdom, China and Ecuador. Samedan maintains three separate
offices in Houston for its international, offshore and onshore oil and gas
operations. NGM's office is located in Houston, Texas and NTI's office is
located in Ardmore, Oklahoma.
OIL AND GAS
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. During
1997, Samedan drilled or participated in the drilling of 384 gross (210.6 net)
wells, comprised of 38 gross (7.7 net) international wells and 346 gross (202.9
net) domestic wells. Additionally, Samedan completed 87 square miles of 3-D and
145 miles of 2-D seismic programs in the Amistad field, Ecuador and two 3-D
seismic programs covering 140 blocks in the Gulf of Mexico. For more information
regarding Samedan's oil and gas properties, see "Item 1. Business -- Oil and
Gas" of this Form 10-K.
Gulf of Mexico. In the Gulf of Mexico during 1997, Samedan drilled or
participated in the drilling of 72 gross wells, 24 exploratory wells (10.99 net)
and 48 development wells (22.28 net) in federal and state waters offshore Texas
and Louisiana. Of the 72 gross wells, 60 wells (27.50 net) were completed as
productive and 12 wells (5.76 net) were abandoned as dry holes. Samedan acquired
24 federal and seven state leases, in the offshore Gulf of Mexico sales during
1997. The Company intends to remain active in these areas of the Gulf of Mexico.
During 1997, a platform drilling rig was utilized on Samedan's 100
percent owned Main Pass 306 E platform, drilling five wells which were being
completed at year end. The wells are expected to deliver approximately 1,000
BBLS of oil per day when fully operational.
Six wells were drilled in Samedan's 50 percent owned Vermilion 279
field during 1997. The wells logged oil and gas pay ranging from 61 to 230 feet
in multiple zones. The field was producing approximately 3,500 BBLS of oil and
50 MMCF of gas per day from eight wells at year end 1997. Two additional wells
remain to be completed, and a third well was being drilled at year end 1997.
During 1998, Samedan expects to drill three additional wells in the field.
Samedan drilled three wells in its East Cameron 331/332 field in which
it owns a 70.4 percent interest. At year end 1997, the A-16 well reached its
target depth encountering approximately 87 feet of oil and gas pay in five
zones. The well is expected to be completed in 1998. During 1998, Samedan
expects to drill one additional well in the field.
At the South Timbalier 195 field, owned 100 percent, Samedan drilled
three wells. One well had been completed at year end 1997, and the remaining two
wells are scheduled to be completed in early 1998. The wells are expected to
deliver approximately 45 MMCF of gas per day when fully operational. At year end
1997, Samedan was preparing to drill one additional well, the A-7.
Samedan installed a 3.5 mile pipeline in the South Timbalier production
area in December 1997. The pipeline will allow for the flow of more gas from the
production area by reducing the pipeline pressure and increasing pipeline
capacity.
8
11
Drilling and completion operations were underway at year end on
Samedan's 50 percent owned Main Pass 261 lease. The field contains three wells;
two of which are completed and awaiting production facilities. The third well
was drilling at year end 1997. Two additional wells are projected to be drilled
in 1998. Production facilities are expected to be operational in the second
quarter of 1998. When fully operational, the field is projected to produce
approximately 40 MMCF of gas and 1,000 BBLS of oil per day, net to Samedan's
interest.
Samedan drilled a successful infill well in its Ship Shoal 315 field.
The 100 percent owned A-1 Sidetrack well encountered approximately 62 feet of
pay in two zones. At year end 1997, the well was producing approximately 1,100
BBLS of oil and 12 MMCF of gas per day.
Samedan made a gas discovery on its 67 percent owned South Timbalier
220 lease during 1997. The discovery well encountered approximately 229 feet of
pay as determined by electric logs. Development plans include drilling an
additional well and installing production facilities. Initial production of
approximately 15 MMCF of gas and 150 BBLS of oil per day, net to Samedan's
interest, is projected to begin in the third quarter of 1998.
Development is underway on Samedan's 25 percent owned East Cameron
371/381 field which was a gas discovery in 400 feet of water. Completion
operations on the two wells drilled and production facilities are scheduled to
be finished in the second quarter of 1998. Two additional wells are scheduled to
be drilled in 1998. Production from the field is expected to be approximately 22
MMCF of gas and 200 BBLS of oil per day, net to Samedan's interest.
An oil discovery was made on Vermilion 379 which is 25 percent owned by
Samedan and located in 325 feet of water. The discovery well was drilled to a
measured depth of 6,253 feet and logged 60 feet of apparent pay in one zone.
Development plans include drilling five additional wells and installing
production facilities. Initial production is expected to commence in the second
quarter of 1999.
At Viosca Knoll 864, Samedan participated with a 35 percent working
interest in a discovery well which logged approximately 200 feet of oil pay in
five zones. The well is located in approximately 1,460 feet of water and tested
oil rates as high as 4,350 BBLS of oil per day. Evaluation of the estimated
development costs and potential reservoir size were underway at year end 1997.
Gulf Coast. During 1997, a productive well was drilled in Samedan's
23.2 percent owned Kaplan field, Vermilion Parish, Louisiana. The well was
completed in the Camerina sand at approximately 16,810 feet. At year end 1997,
the well was producing approximately 20 MMCF of gas and 800 BBLS of condensate
per day. During 1998, Samedan anticipates participating in the drilling of three
additional wells in the field.
Samedan successfully recompleted the Glenn #3 well in the South Lake
Arthur gas field, Vermilion Parish, Louisiana. The well was plugged back to the
Miogyp sand at 16,735 feet and was flowing 13.7 MMCF of gas per day at year end
1997.
Samedan also has a deep gas prospect lying beneath the South Lake
Arthur field which encompasses approximately 5,000 acres. In order to test the
deep prospective zone Samedan expects to drill a 20,000 foot test well in 1998.
In South Texas, seven wells were drilled in Samedan's 100 percent owned
Rincon field, located in Starr County. The wells were completed in the Rincon or
Vicksburg sands. During 1998, five wells are expected to be drilled.
Mid Continent. Samedan is actively drilling wells in its multiple
objective Washita Mountain Front play in Beckham County, Oklahoma. Samedan
participated in drilling eight wells during the year and each encountered 30 to
250 feet of oil and gas pay in multiple zones, as determined from electric logs.
Samedan owns approximately 40
9
12
percent in 26,000 gross acres in the prospect. During 1998, Samedan expects to
participate in drilling 15 wells. Additionally, Samedan has a 45 percent
participation interest in a 3-D seismic program covering 227 square miles within
this area.
Rocky Mountain. Samedan drilled 100 wells in its Bowdoin gas field
located in Phillips and Valley counties, Montana. The wells were completed in
the field pay, but also encountered a new shallow pay zone in the Niobrara
formation. Gas from the field is sold under a long-term contract in which the
price escalates monthly through May 2007. At year end 1997, the price was $4.31
per MMBTU.
In Dawson County, Montana, Samedan kept a drilling rig engaged
throughout 1997, drilling horizontal oil wells in its Deer Creek prospect. Seven
wells were drilled in the field during 1997, including five wells that had
multiple lateral well bores. The typical well in the field stabilizes production
at approximately 100 BBLS of oil per day. Samedan owns a 75 percent working
interest in the prospect and anticipates keeping a rig active throughout 1998.
Argentina. Throughout 1997, two drilling rigs were utilized for
expanding infill drilling in the El Tordillo oil field. At year end 1997, a
third rig was placed in service to accelerate the drilling program. Twenty-six
wells were completed in the main field during the year and drilling to a
prospective deeper horizon was in process at year end. Samedan owns 13.7 percent
interest in the El Tordillo field which in 1997 produced an average of 2,800
BBLS of oil per day, net to Samedan's interest.
China. Samedan opened its Beijing, China office during 1997 to operate
its existing exploration activities and seek additional opportunities. Samedan
currently owns and operates the Cheng Dao Xi and Cheng Zi Kou concessions in the
southern portion of Bo Hai Bay, China. Samedan also owns a one-third interest in
the Laopu and Getuo concessions located in the northern portion of Bo Hai Bay.
During 1997, Samedan drilled a dry hole on the Laopu concession.
Drilling plans for 1998 include three wells on the Cheng Dao Xi
concession and one well on the Getuo concession. It is anticipated that a
drilling rig will be available during the second quarter of 1998 and two of the
Cheng Dao Xi wells will be drilled consecutively. If successful, Samedan intends
to present a development plan to the Chinese government for the Cheng Dao Xi
field during 1998.
Ecuador. In 1997, Samedan opened an office in Guayaquil, Ecuador to
manage the activities of its 864,126 acre offshore concession. The concession
includes the Amistad gas field which was discovered in 1970, but was never
developed. Additionally, during the year Samedan completed an 87 square mile 3-D
seismic program on the Amistad gas field and a 145 mile 2-D seismic program
within the concession. Samedan's Ecuador staff is focused on developing a gas
market for the Amistad field. The best prospect appears to be supplying fuel to
electric power plants. Ecuador's existing plants currently burn imported diesel
or bunker fuel. Samedan is negotiating with the government and power producers
to determine a mutually beneficial price and deliverability arrangement.
Equatorial Guinea. Samedan will be participating, with a 35 percent
expense interest, in a joint venture to construct a methanol plant in Equatorial
Guinea. The plant is estimated to cost $317 million and is being designed to
produce 2,500 metric tons of methanol per day, which equates to approximately
20,000 BBLS per day. The plant will use the gas from Samedan's 35 percent owned
Alba field as feedstock. The plant is being designed to utilize approximately
115 MMCF of gas per day. The gas will be priced at $.25 per MMBTU. The
construction contract stipulates that first commercial production of methanol
should be achieved by January 2001. Current marketing plans are to enter into
long-term contracts with methanol users in the United States and Europe.
As a result of developing an economic market for the Alba gas through
the methanol plant, Samedan added 322.2 BCF of gas to its proved reserves in
1997. Based upon its cash flow projections from methanol sales with the $.25 per
MMBTU wellhead price, Samedan expects to realize a blended value of
approximately $3.83 per MCF for its gas production from the Alba field. Based
upon reserve estimates, the Alba field can deliver sufficient gas for the
10
13
plant to operate for 30 years. In conjunction with the plant investment, the
Alba field owners are evaluating a plan to drill additional wells, install a
platform and construct a pipeline system. The plan includes evaluating gas
reinjection which would accelerate condensate production. During 1997, the Alba
field produced approximately 2,300 BBLS of condensate per day, net to Samedan's
interest.
U.K. Sector of the North Sea. Production commenced from Samedan's 20
percent owned Windermere property in mid 1997. The field, located in the
southern gas basin of the North Sea, was producing 13.1 MMCF of gas per day at
year end, net to Samedan's interest.
Development operations are underway for Samedan's 25 percent owned
Malory field which is also located in the southern gas basin of the North Sea.
Samedan estimates the production will commence in the fourth quarter of 1998.
Samedan's projected share of production will be approximately 7.5 MMCF per day.
At year end 1997, Samedan was drilling an exploratory well on the Goldeneye
prospect in the North Sea.
Oil and Gas Reserves and Standardized Measure. The following table
summarizes the estimated proved oil and gas reserves of Samedan and the
standardized measure of discounted future net cash flows attributed thereto, as
of December 31, 1997, 1996 and 1995. Additional information is contained in
"Item 8. Financial Statements and Supplementary Data--Supplemental Oil and Gas
Information (Unaudited)" of this Form 10-K, and incorporated herein by
reference.
1997 1996 1995
-------------------------------- ----------------------------- ---------------------------
(dollars in millions) U.S. Int'l TOTAL U.S. Int'l TOTAL U.S. Int'l TOTAL
- --------------------------------------------------------------------------------------------------------------------
PROVED RESERVES:
Natural gas and
casinghead
gas (MMCF) 1,107,158 375,057 1,482,215 1,079,607 76,643 1,156,250 818,301 32,038 850,339
Crude oil and
condensate (BBLS
in thousands) 89,065 41,798 130,863 82,317 33,430 115,747 70,907 13,101 84,008
STANDARDIZED MEASURE
OF DISCOUNTED FUTURE
NET CASH FLOWS $1,063 $289 $1,352 $1,967 $255 $2,222 $1,173 $101 $1,274
Samedan has less than five percent of its oil and gas sales volumes
committed to long-term supply contracts and has no similar agreements with
foreign governments or authorities in which Samedan acts as producer as of year
end 1997.
Since January 1, 1997, 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.
At January 30, 1998, Samedan was drilling 32 gross (15.9 net)
exploratory wells, and 15 gross (6.6 net) development wells. These wells are
located onshore in the United States in California, Colorado, Louisiana, North
Dakota, Oklahoma, Texas, Wyoming, Offshore Gulf of Mexico and internationally in
Argentina and the U.K. Sector of the North Sea. These wells have objectives
ranging from approximately 3,700 to 18,000 feet. The estimated drilling cost to
Samedan of these wells is approximately $42.7 million if all are dry and
approximately $61 million if all are completed as producing wells.
11
14
Net Exploratory and Developmental Wells. 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. 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.
Net Exploratory Wells Net Development Wells
Productive(1) Dry(2) Productive(1) Dry(2)
------------------------------------------------ -------------------------------------------------
Year Ended
December 31, U.S. International U.S. International U.S. International U.S. International
- ----------------------------------------------------------------------------------------------------------------------
1995 12.44 .80 14.42 4.72 107.09 5.50 20.49 .14
1996 15.37 .69 22.16 1.04 74.97 1.17 19.91
1997 13.98 .76 25.08 3.79 155.93 3.13 7.89
(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.
Average Sales Price. The following table sets forth for each of the
last three years the average sales price per unit of oil produced and per unit
of natural gas produced, and the average production cost per unit.
Year Ended December 31,
------------------------------------------
1997 1996 1995
- ----------------------------------------------------------------------------------------------------------
Average sales price per BBL of oil (1):
United States $ 18.49 $17.83 $ 16.80
International $ 15.55 $20.32 $ 15.57
Combined (2) $ 17.86 $18.28 $ 16.78
Average sales price per MCF of natural gas (1):
United States $ 2.48 $ 2.18 $ 1.75
International $ 2.29 $ 1.90 $ 1.02
Combined (3) $ 2.48 $ 2.17 $ 1.72
Average production (lifting) cost per unit of oil and
natural gas production, excluding depreciation
(per equivalent BBL)(4):
United States $ 3.85 $ 3.45 $ 4.17
International $ 4.60 $ 6.47 $ 4.70
Combined $ 3.93 $ 3.70 $ 4.21
(1) Net production amounts used in this calculation include royalties.
12
15
(2) Reflects a reduction of $.19 per BBL in 1997 and $2.35 per BBL in 1996
and includes an increase of $.16 per BBL in 1995 from hedging.
(3) Reflects a reduction per MCF of $.12 in 1997, $.33 in 1996 and $.004 in
1995 from hedging.
(4) Gas production is converted to oil BBL equivalents based on the average
sales prices per BBL 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 exclude royalties. Conversion ratios for
1997, 1996 and 1995 are set forth below:
United States International
------------- -------------
1997 7.44 to 1 6.71 to 1
1996 8.12 to 1 10.66 to 1
1995 9.61 to 1 16.43 to 1
13
16
OFFSHORE GULF OF MEXICO OPERATIONS
as of December 31, 1997
[MAP]
SIGNIFICANT OFFSHORE UNDEVELOPED LEASE HOLDINGS (interests rounded to nearest
whole percent)
Net Working Net Working Net Working Net Working
Block Interest(%) Block Interest(%) Block Interest(%) Block Interest(%)
- -------------------------------------------------------------------------------------------------------------------------
Matagorda Island (Brazos) East Cameron Vermilion Viosca Knoll
- ------------------------- ------------ --------- ------------
441-L 100 16 95 64 100 251 40
450-L 100 71 73 103 100 864* 35
439-L 100 142 40 111 95 Garden Banks
East Breaks 154 38 163 50 ------------
- ----------- 161 50 194 25 35 100
208* 40 178 32 263 100 62 25
475* 100 West Cameron 278 50 63 25
519* 100 ------------ 283 50 64 25
563* 100 499 75 286 100 78 100
Ship Shoal 518 75 293 50 107 25
- ---------- 583 100 310 50 115 100
313 40 602 100 312 100 116 100
West Delta 604 50 337 98 122 100
- ---------- 619 33 342 38 163 100
59 25 644 25 343 73 326* 100
Green Canyon Breton Sound 345 75 534* 35
- ------------ ------------ 347 71 536* 35
23* 50 41 95 349 75 537* 35
Eugene Island 42 95 350 75 538* 35
- ------------- 49 95 352 74 578* 35
84 95 50 95 358 55 580* 35
300 67 South Pass 360 67 581* 35
South Marsh Island ---------- 361 67 582* 35
- ------------------ 41 50 365 50 625* 35
62 67 43 50 366 75 751* 100
63 67 58 48 372 74 795* 100
65 67 South Timbalier 374 55 Galveston
104 100 --------------- 392 38 ---------
179 35 98 50 394 75 249-L 50
180 35 156 67 402 30 250-L 50
185 35 174 100 407 38 277-L 50
186 35 201 100 408 38 338-S 50
191 50 207 100 349-S 50
Mississippi Canyon Ewing Bank
- ------------------ ----------
573 100 993 50
705 25
583* 50
618* 50
*Located in water deeper than 1,000 feet.
14
17
The developed and undeveloped acreage (including both leases and
concessions) that Samedan held as of December 31, 1997, is as follows:
Developed Acreage (1)(2) Undeveloped Acreage (2)(3)
----------------------------- -----------------------------
Location Gross Acres Net Acres Gross Acres Net Acres
- -------------------------------------------------------------------------------------------------------------------
United States Onshore
Alabama 2,610 1,264 3,391 1,368
California 21,475 10,684 15,896 9,473
Colorado 67,665 63,364 44,330 35,773
Kansas 96,608 58,076 19,715 12,097
Louisiana 43,171 23,868 7,570 4,031
Michigan 637 151 2,423 557
Mississippi 13,077 7,827 4,339 2,073
Montana 176,123 120,714 100,906 53,307
New Mexico 5,875 3,107 80,858 51,574
North Dakota 24,290 11,416 42,052 25,269
Oklahoma 166,114 66,320 56,728 23,427
Texas 137,616 58,828 149,102 47,472
Wyoming 34,276 13,874 43,310 15,252
Other 5,760 2,893 3,940 2,058
- -------------------------------------------------------------------------------------------------------------------
Total United States Onshore 795,297 442,386 574,560 283,731
- -------------------------------------------------------------------------------------------------------------------
United States Offshore (Federal Waters)
Alabama 11,520 5,822 149,760 65,108
California 17,280 2,938 79,678 8,625
Louisiana 723,217 301,391 445,609 232,910
Mississippi 10,891 7,260 50,815 36,895
Texas 319,169 91,491 182,399 120,347
- -------------------------------------------------------------------------------------------------------------------
Total United States Offshore (Federal Waters) 1,082,077 408,902 908,261 463,885
- -------------------------------------------------------------------------------------------------------------------
International
Argentina 28,988 3,778 85,760 11,177
Australia 938,980 373,244
China 316,676 161,558
Ecuador 864,126 864,126
Equatorial Guinea 26,651 9,272 284,000 98,806
Ireland 296,797 169,174
Portugal 343,455 154,554
United Kingdom 125,107 12,423 533,816 165,387
Other 777,277 32,063
- -------------------------------------------------------------------------------------------------------------------
Total International 180,746 25,473 4,440,887 2,030,089
- -------------------------------------------------------------------------------------------------------------------
Total 2,058,120 876,761 5,923,708 2,777,705
- -------------------------------------------------------------------------------------------------------------------
(1) Developed acreage is acreage spaced or assignable to productive wells.
(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.
(3) 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.
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.
15
18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during
the fourth quarter of 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of March 16,
1998, with respect to the executive officers of the Registrant.
Name Age Position
- -------------------------------------------------------------------------------------------------------------
Robert Kelley (1) 52 Chairman of the Board, President, Chief Executive Officer, Director
George L. DeMare Jr. (2) 52 Senior Vice President and Operating Committee Member of Samedan
William D. Dickson (3) 49 Senior Vice President-Finance and Treasurer of the Registrant and
Operating Committee Member of Samedan
Dan O. Dinges (4) 44 Senior Vice President and Operating Committee Member of Samedan
W. A. Poillion (5) 48 Senior Vice President and Operating Committee Member of Samedan
Orville Walraven (6) 53 Corporate Secretary of the Registrant and Senior Vice President and
Operating Committee Member of Samedan
James C. Woodson (7) 55 Senior 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 August 1986, he had served as Executive Vice
President of the Registrant from January 1986. Mr. Kelley also serves as
President and Chief Executive Officer of Samedan, positions he has held
since 1984. For more than five years prior thereto, Mr. Kelley served as
an officer of Samedan. He has served as a director of the Company since
1986.
(2) George L. DeMare, Jr. was promoted to Senior Vice President and Onshore
Division Manager of Samedan on January 1, 1998. Prior thereto, he had
served as Vice President and Onshore Division Manager of Samedan since
1989. Mr. DeMare has been a member of the Operating Committee of Samedan
since January 31, 1995.
(3) William D. Dickson was promoted to Senior Vice President-Finance and
Treasurer on January 1, 1998. Prior thereto, he served as Vice
President-Finance and Treasurer of the Company since 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 was promoted to Senior Vice President and Division General
Manager, Offshore Division of Samedan on January 1, 1998. Prior thereto,
he served as Vice President and 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 was promoted to Senior Vice President-Production and
Drilling of Samedan on January 1, 1998. Prior thereto, he served as Vice
President-Production and Drilling and a member of the operating
committee of Samedan since November 1, 1990. From March 1, 1985 to
October 31, 1990, he served as Manager of Offshore Production and
Drilling for Samedan.
16
19
(6) Orville Walraven has served as Corporate Secretary of the Registrant
since January 1, 1989. He was promoted to Senior Vice President-Land of
Samedan on January 1, 1998. Prior thereto, he 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 was promoted to Senior Vice President-Exploration of
Samedan on January 1, 1998. Prior thereto, he served as Vice
President-Exploration since September 1, 1983. Mr. Woodson has been a
member of the Operating Committee of Samedan since August 1, 1986.
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.
17
20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Common Stock. The Registrant's Common Stock, $3.33 1/3 par value
("Common Stock"), is listed and traded on the New York Stock Exchange under the
symbol "NBL." The declaration and payment of dividends are at the discretion of
the Board of Directors of the Registrant and the amount thereof will depend on
the Registrant's results of operations, financial condition, contractual
restrictions, cash requirements, future prospects and other factors deemed
relevant by the Board of Directors.
Stock Prices and Dividends by Quarters. The following table sets forth,
for the periods indicated, the high and low sales price per share of Common
Stock on the New York Stock Exchange and quarterly dividends paid per share.
Dividends
High Low Per Share
- ----------------------------------------------------------------------------
1997
- ----
First quarter $ 50 $ 37 1/2 $.04
Second quarter $ 43 3/4 $ 32 1/4 $.04
Third quarter $ 47 9/16 $ 38 1/8 $.04
Fourth quarter $ 46 $ 32 3/16 $.04
1996
- ----
First quarter $ 33 3/8 $ 26 7/8 $.04
Second quarter $ 38 3/8 $ 32 1/8 $.04
Third quarter $ 42 1/2 $ 37 3/8 $.04
Fourth quarter $ 49 $ 41 5/8 $.04
Transfer Agent and Registrar. The transfer agent and registrar for the
Common Stock is Bank One N.A., Post Office Box 26848, Oklahoma City, Oklahoma
73125.
Stockholders' Profile. As of December 31, 1997, the number of holders
of record of Common Stock was 1,512. The following chart indicates the common
stockholders by category.
Shares
December 31, 1997 Outstanding
- --------------------------------------------------------------------------------------------------------------
Individuals 514,165
Joint accounts 79,116
Fiduciaries 185,050
Institutions 2,559,070
Nominees 53,560,652
Foreign 485
- --------------------------------------------------------------------------------------------------------------
Total 56,898,538
- --------------------------------------------------------------------------------------------------------------
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21
ITEM 6. SELECTED FINANCIAL DATA.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts and ratios) 1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------
REVENUES AND INCOME
Revenues $1,116,623 $ 887,203 $ 487,018 $ 358,389 $ 286,583
Net cash provided by operating activities 445,571 380,945 238,920 188,621 139,381
Net income 99,278 83,880 4,086 3,166 12,625
PER SHARE DATA
Basic earnings per share $ 1.75 $ 1.63 $ .08 $ .06 $ .26
Cash dividends $ .16 $ .16 $ .16 $ .16 $ .16
Year end stock price $ 35.25 $ 47.88 $ 29.88 $ 24.75 $ 26.50
Basic weighted average shares outstanding 56,872 51,414 50,046 49,970 48,098
FINANCIAL POSITION (at year end)
Property, plant and equipment, net:
Oil and gas mineral interests,
equipment and facilities $1,546,426 $1,559,691 $ 831,827 $ 804,009 $ 784,235
Total assets 1,875,484 1,956,938 989,176 933,516 1,067,996
Long-term obligations:
Long-term debt, net of current portion 644,967 798,028 376,992 376,956 453,760
Deferred income taxes 144,083 108,434 69,445 61,802 45,108
Other 56,425 50,603 33,650 19,455 7,158
Shareholders' equity 812,989 720,067 411,911 412,066 415,432
Ratio of debt to book capital .44 .54 .48 .48 .52
CAPITAL EXPENDITURES
Oil and gas mineral interests,
equipment and facilities $ 320,561 $ 982,499 $ 252,977 $ 158,973 $ 508,506
Other 8,499 3,485 6,265 2,371 1,607
- -----------------------------------------------------------------------------------------------------------------------
Total capital expenditures $ 329,060 $ 985,984 $ 259,242 $ 161,344 $ 510,113
- -----------------------------------------------------------------------------------------------------------------------
For additional information, see "Item 8. Financial Statements and Supplementary
Data" of this Form 10-K.
OPERATING STATISTICS
Year ended December 31,
- ------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
GAS
Sales (in millions) $ 499.4 $ 365.4 $ 167.4 $ 174.5 $ 159.2
Production (MMCF per day) 565.4 469.4 272.2 247.6 211.1
Average price (per MCF) $ 2.48 $ 2.17 $ 1.72 $ 1.97 $ 2.10
OIL
Sales (in millions) $ 243.6 $ 225.2 $ 153.5 $ 122.9 $ 111.3
Production (BBLS per day) 38,345 34,520 25,617 22,751 19,496
Average price (per BBL) $ 17.86 $ 18.28 $ 16.78 $ 14.90 $ 15.91
Royalty sales (in millions) $ 18.1 $ 13.9 $ 7.2 $ 8.8 $ 7.5
19
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
SIGNIFICANT EVENTS IN 1997
o For eight straight years the Company recorded record levels of gas production.
o For nine straight years the Company recorded record levels of oil production.
o The Company expended $356.9 million on acquisition, exploration and
development costs during 1997.
o The Company added 34.6 million BBLS of oil and 557.4 BCF of gas to its reserve
base in 1997 primarily through drilling.
o During 1997, the Company sold non-strategic Canadian properties for $43.1
million.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $445.6 million for 1997,
a 17 percent and 86.5 percent increase from the $380.9 million and $238.9
million in 1996 and 1995, respectively. Cash and short-term cash investments
decreased to $55.1 million at December 31, 1997, from $94.8 million at year-end
1996.
During 1997, the Company utilized its beginning cash balance and cash
flow from operations to fund its exploration and development expenditures, as
well as to repay $203 million in long-term debt.
The Company's current ratio (current assets divided by current
liabilities) was 1.19:1 at December 31, 1997, compared with 1.13:1 at December
31, 1996.
RESERVES ADDED AND COST OF FINDING
During 1997, the Company spent $356.9 million on acquisitions,
exploration and development of oil and gas properties. Total proved gas reserves
increased from 1.16 TCF at year-end 1996 to 1.48 TCF at year-end 1997, and total
proved oil reserves increased from 115.7 million BBLS at year-end 1996 to 130.9
million BBLS at year-end 1997.
An accepted method of calculating cost of finding is to divide the
Company's expenditures for oil and gas acquisition, exploration and development
by the net BOE's added during the year. Using this method, the Company's cost of
finding for 1997 was $2.80 per BOE.
A three year summary of cost of finding follows:
Three
(BOE's and Dollars stated in millions, Year
except finding cost) 1997 1996 1995 Total
-------------------------------------------------------------------------------------------------------
Oil reserves added 34.6 46.3 18.2 99.1
Gas reserves added BOE (6:1) 92.9 88.0 29.0 209.9
-------------------------------------------------------------------------------------------------------
Total reserves added BOE 127.5 134.3 47.2 309.0
-------------------------------------------------------------------------------------------------------
Costs incurred in oil and gas
acquisition, exploration
and development activities $356.9 $1,009 $ 266 $1,631.9
Average finding cost per BOE $ 2.80 $ 7.51 $ 5.64 $ 5.28*
- ----------------------------
*Three year weighted average
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FINANCING
Total long-term debt at December 31, 1997 was $645 million compared to
$848 million (including current portion) at December 31, 1996, a decrease of 24
percent. The ratio of debt to book capital (defined as the Company's debt plus
its equity) was 44 percent at December 31, 1997, compared with 54 percent at
December 31, 1996.
The $300 million credit agreement is a revolving credit facility with a
group of banks with a final maturity of December 24, 2002. The interest rate
charged, which is based upon a Eurodollar rate plus 22.5 basis points, was 5.9
percent at December 31, 1997. Financial covenants include maintenance of a cash
flow multiple of at least four times interest cost and maintenance of a debt
level which does not exceed 60 percent of the Company's shareholders' equity
plus its debt.
The $800 million credit agreement was terminated on December 24, 1997,
and the outstanding balance of $200 million was refinanced in the $300 million
credit agreement. The weighted average interest rate on the borrowings during
1997 was 6.9 percent.
Total long-term debt outstanding at December 31, 1997, included $100
million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, and
$100 million of 7 1/4 % Senior Debentures Due 2097.
The only principal payment on long-term debt due during the next five
years is the outstanding balance of the $300 million credit agreement on
December 24, 2002.
On November 1, 1996, all of the Company's $230 million 4 1/4%
Convertible Subordinated Notes Due 2003 were converted into 6,275,510 shares of
common stock.
OTHER
The Company follows an entitlements method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $18.5 million
and $19.3 million at December 31, 1997 and 1996, respectively, and estimated gas
imbalance liabilities were $21.6 million and $21.7 million at December 31, 1997
and 1996, respectively. These imbalances are valued at the amount that 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 pretax gains of approximately $15.9
million, $1.9 million and $3.6 million for 1997, 1996 and 1995, respectively.
Total amounts of oil and gas reserves associated with these dispositions during
the last three years were 6.6 million BBLS of oil and 89.3 BCF of gas. In 1997,
the Company sold its Canadian operations for $43.1 million, with estimated
reserves sold of 2.6 million BBLS of oil and 23.1 BCF of gas. The Company
believes the disposition 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
1989, and currently anticipates it will continue to pay quarterly dividends of
$.04 per share.
In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation." The Company adopted the disclosure requirements of
SFAS No. 123 during 1996 and has presented in the footnotes to its financial
statements pro forma disclosure as if the provisions of SFAS No. 123 had been
adopted for all years reported within the Company's financial statements.
21
24
The Financial Accounting Standards Board issued SFAS No. 128 "Earnings
per Share," SFAS No. 129 "Disclosure of Information about Capital Structure,"
SFAS No. 130 "Reporting Comprehensive Income" and SFAS No. 131 "Disclosure about
Segments of an Enterprise and Related Information," in the first half of 1997.
SFAS No. 128 and No. 129 are effective for the Company's financial statements in
both interim and annual periods ending after December 15, 1997. SFAS No. 130 and
No. 131 are effective for 1998. The Company adopted disclosure requirements of
SFAS No. 128 and No. 129 in 1997 and has presented disclosure as if the
provisions of SFAS No. 128 and No. 129 had been adopted for all years reported
within the Company's financial statements.
RESULTS OF OPERATIONS
The Company's consolidated financial statements for the year ended
December 31, 1997, include a full year of EDC operations as a wholly owned
subsidiary of Samedan. The consolidated financial statements for the year ended
December 31, 1996, include five months of consolidated operations. EDC was
acquired by the Company on July 31, 1996.
NET INCOME AND REVENUES
1997 VERSUS 1996. Net income for 1997 was $99.3 million, or $1.75 per
share, compared with $83.9 million, or $1.63 per share in 1996. The increase in
net income was achieved through record gas production, substantially higher gas
prices and the sale of non-strategic properties. Total revenues were $1,116.6
million in 1997 and $887.2 million in 1996.
Oil and gas revenues were $761.1 million in 1997, an increase of $156.5
million, or 26 percent, over 1996. The Company received an average oil price for
1997 of $17.86 per BBL, a two percent decrease from the average 1996 price of
$18.28 per BBL. The average gas price increased 14 percent in 1997 to $2.48 per
MCF from the 1996 average of $2.17 per MCF.
Gathering, marketing and processing revenues were $329.9 million, an
increase of 21 percent from the $273.7 million in 1996. The increase reflects an
increase in marketed volumes for each of NTI and NGM, both wholly owned
subsidiaries of the Company.
Other income in 1997 was $25.6 million, compared with $8.9 million in
1996. Other income in 1997 included non-recurring income of $14.1 million
resulting from the Company's sale of its Canadian operations, with estimated
reserves sold of 2.6 million BBLS of oil and 23.1 BCF of gas. The proceeds of
$43.1 million received from the sale of the Canadian properties were used to
reduce the Company's debt existing under its credit agreement.
1996 VERSUS 1995. Net income for 1996 was $83.9 million, or $1.63 per
share, compared with $4.1 million, or $.08 per share in 1995. The increase in
net income was achieved through increased oil and gas production and
substantially higher oil and gas prices. Total revenues were $887.2 million in
1996 and $487.0 million in 1995.
Oil and gas revenues were $604.6 million in 1996, an increase of $276.5
million, or 84 percent, over 1995. The Company received an average oil price for
1996 of $18.28 per BBL, a nine percent increase from the average 1995 price of
$16.78 per BBL. The average gas price increased 26 percent in 1996 to $2.17 per
MCF from the 1995 average of $1.72 per MCF. The increase in gas price was due
primarily to higher demand and lower levels of gas storage than in the previous
year.
Gathering, marketing and processing revenues were $273.7 million, an
increase of 143 percent from the $112.7 million in 1995. The increase reflects a
full year of operations for NTI and NGM.
Other income in 1996 was $8.9 million, compared with $46.2 million in
1995. Other income in 1995 included non-recurring income of $39.0 million
resulting from the settlement of a Columbia Gas Transmission Corporation
bankruptcy claim with Samedan.
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NATURAL GAS INFORMATION
A three-year summary of gas-related information follows:
1997 1996 1995
-------------------------------------------------------------------------------------------------------
Proved reserves at year end (MMCF) 1,482,215 1,156,250 850,339
Gas revenues (millions) $ 499.4 $ 365.4 $ 167.4
Average price per MCF* $ 2.48 $ 2.17 $ 1.72
Average daily production (MMCF) 565.4 469.4 272.2
Gas sales as a percent of oil and gas sales 67% 62% 52%
- --------------------
*The average price reflects a reduction per MCF of $.12 in 1997, $.33 in
1996 and $.004 in 1995 from hedging.
1997 VERSUS 1996. Gas sales for 1997 increased 37 percent to $499.4
million from $365.4 million in 1996. Average daily production in 1997 increased
20 percent to 565.4 MMCF from 469.4 MMCF in 1996.
The average gas price in 1997 increased 14 percent to $2.48 per MCF
from $2.17 per MCF in 1996. During 1997, the Company's average gas prices ranged
from a low of $1.80 in April to a high of $3.35 in January.
International sales accounted for three percent of 1997 gas sales
compared with two percent in 1996. Average daily gas production outside of the
United States was 20,873 MCF in 1997 and 5,757 MCF in 1996.
1996 VERSUS 1995. Gas sales for 1996 increased 118 percent to $365.4
million from $167.4 million in 1995. Average daily production in 1996 increased
72 percent to 469.4 MMCF from 272.2 MMCF in 1995.
The average gas price in 1996 increased 26 percent to $2.17 per MCF
from $1.72 per MCF in 1995. During 1996, the Company's average gas prices ranged
from a low of $1.82 in April and October to a high of $3.15 in December.
CRUDE OIL INFORMATION
A three-year summary of oil-related information follows:
1997 1996 1995
-------------------------------------------------------------------------------------------------------
Proved reserves at year end
(thousands of BBLS) 130,863 115,747 84,008
Oil revenues (millions) $ 243.6 $ 225.2 $ 153.5
Average price per BBL* $ 17.86 $ 18.28 $ 16.78
Average daily production (BBLS) 38,345 34,520 25,617
Oil sales as a percent of
oil and gas sales 33% 38% 48%
- --------------------
*The average price reflects a reduction of $.19 per BBL in 1997 and $2.35
per BBL in 1996 and includes an increase of $.16 per BBL in 1995 from
hedging.
1997 VERSUS 1996. Oil sales for 1997 increased eight percent to $243.6
million from $225.2 million in 1996. Average daily production in 1997 increased
11 percent to 38,345 BBLS from 34,520 BBLS in 1996.
The average oil price for 1997 was $17.86 per BBL, a two percent
decrease from the 1996 average of $18.28 per BBL. The Company's 1997 average oil
prices ranged from a low of $15.74 per BBL in December to a high of $21.92 per
BBL in January.
23
26
International sales accounted for 19 percent of 1997 oil sales compared
with 20 percent in 1996. Average daily oil production outside the United States
was 8,250 BBLS in 1997 and 6,230 BBLS in 1996.
1996 VERSUS 1995. Oil sales for 1996 increased 47 percent to $225.2
million from $153.5 million in 1995. Average daily production in 1996 increased
35 percent to 34,520 BBLS from 25,617 BBLS in 1995.
The average oil price for 1996 was $18.28 per BBL, a nine percent
increase from the 1995 average of $16.78 per BBL. The Company's 1996 average oil
prices ranged from a low of $17.11 per BBL in January to a high of $19.74 per
BBL in September.
International sales accounted for 20 percent of 1996 oil sales compared
with 15 percent in 1995. Average daily oil production outside the United States
was 6,230 BBLS in 1996 and 3,777 BBLS in 1995.
HEDGING ACTIVITY
The Company, through its subsidiaries, from time to time, uses various
hedging arrangements in connection with anticipated crude oil and natural gas
sales of its production to minimize the impact of product price fluctuations.
Such arrangements include fixed price hedges, costless collars and other
contractual arrangements. Although these hedging arrangements expose the Company
to credit risk, the Company monitors the creditworthiness of its counterparties,
which generally are major institutions, and believes that losses from
nonperformance are unlikely to occur. Hedging gains and losses related to the
Company's oil and gas production are recorded in oil and gas sales and
royalties.
During 1997, the Company had natural gas hedging contracts that ranged
from 20 percent to 32 percent of its average daily natural gas production.
Natural gas hedges were in the price range of $1.88 to $3.30 per MMBTU. The net
effect of these 1997 hedges was a $.12 per MCF reduction in the average natural
gas price realized by the Company. At December 31, 1997, the Company had no
natural gas hedging contracts.
During 1997, the Company had crude oil hedging contracts that ranged
from 19 percent to 50 percent of its average daily oil production. Crude oil
hedges were in the price range of $16.81 to $24.35 per BBL. The net effect of
these 1997 hedges was a $.19 per BBL reduction in the average crude oil price
realized by the Company. At December 31, 1997, the Company had no crude oil
hedging contracts.
During 1996, the Company had natural gas hedging contracts that ranged
from 39 percent to 86 percent of its average daily natural gas production.
Natural gas hedges were in the price range of $1.60 to $3.59 per MMBTU. The net
effect of these 1996 hedges was a $.33 per MCF reduction in the average natural
gas price. At December 31, 1996, the Company was a party to natural gas hedging
contracts to hedge approximately 21 percent of its estimated 1997 average daily
natural gas production at an average price per MMBTU of $2.20.
During 1996, the Company had crude oil hedging contracts that ranged
from 48 percent to 55 percent of its average daily oil production for January
through July and 62 percent to 100 percent of its average daily oil production
for August through December. Crude oil hedges were in the price range of $16.50
to $24.27 per BBL. The net effect of these 1996 hedges was a $2.35 per BBL
reduction in the average crude oil price. At December 31, 1996, the Company was
a party to crude oil hedging contracts to hedge approximately 26 percent of its
estimated 1997 annual crude oil production at an average price per BBL of
$20.48.
During 1995, Samedan had natural gas hedging contracts for November and
December to hedge from 20 percent to 46 percent of its average daily natural gas
production. For May to December 1995, Samedan had hedged approximately 20
percent of its daily crude oil production. Natural gas hedges were in the range
of $1.60 to $1.96 per MMBTU and crude oil hedges were in the range of $18.56 to
$20.27 per BBL. The net effect of these 1995 hedges was a $.004 per MCF
reduction in the average natural gas price and a $.16 per BBL increase in the
average crude oil price realized by the Company.
24
27
In addition to the hedging arrangements pertaining to the Company's
production as described above, NGM employs various hedging arrangements in
connection with its purchases and sales of third party production to lock in
profits or limit exposure to gas price risk. Most of the purchases made by NGM
are on an index basis; however, purchasers in the markets in which NGM sells
often require fixed or NYMEX related pricing. NGM may 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 1997, NGM had hedging
transactions with broker-dealers that ranged from 317,693 MMBTU's to 768,599
MMBTU's of gas per day.
At December 31, 1997, NGM had in place hedges ranging from
approximately 645 MMBTU's to 29,279 MMBTU's of gas per day for January 1998 to
March 1999 for future physical transactions. At December 31, 1996, NGM had in
place hedges ranging from approximately 7,475 MMBTU's to 551,126 MMBTU's of gas
per day for January 1997 to March 1998 for future physical transactions. 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. 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.
COSTS AND EXPENSES
1997 VERSUS 1996. Oil and gas exploration expense increased in 1997 by
$36.8 million from 1996 to $86.7 million. The increase resulted primarily from a
$14.1 million increase in dry hole expense and a full year of EDC foreign
exploration costs for 1997.
Oil and gas operations expense in 1997 increased $34.7 million from
1996 to $160.8 million. Lease operating expense increased $35 million in 1997
due to higher oil and gas production and a full year's ownership of EDC
properties. Production taxes increased $1.8 million in 1997 due to higher
production levels and gas prices.
In 1997, depreciation, depletion and amortization ("DD&A") expense
increased $67 million over 1996 due to the higher production levels and a full
year of production from the EDC properties. The unit rate of DD&A expense per
BOE, converting gas to oil on a 6:1 basis, was $6.33 for 1997, compared with
$5.66 for 1996.
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 $59.5 million for such future restoration and dismantlement
costs which are classified in accumulated DD&A on the balance sheet at December
31, 1997. Total estimated future dismantlement and restoration costs of $143.9
million are included in future production and development costs for purposes of
estimating the future net revenues relating to the Company's proved reserves.
1996 VERSUS 1995. Oil and gas exploration expense increased in 1996 by
$16.6 million from 1995 to $49.9 million. The increase resulted primarily from a
$15.2 million increase in dry hole expense for 1996.
Oil and gas operations expense in 1996 increased $44.3 million from
1995 to $126 million. Lease operating expense increased $37.7 million in 1996
due to higher oil and gas production from a greater number of properties and the
acquisition of EDC. Production taxes increased $6.7 million in 1996 due to
higher production levels and oil and gas prices.
In 1996, DD&A expense increased $32.7 million over 1995 due to the
record production levels and the EDC acquisition. The unit rate of DD&A expense
per BOE, converting gas to oil on a 6:1 basis, was $5.66 for 1996, compared with
$7.75 for 1995. The 1995 rate included $59.5 million of additional impairment
for the writedown of certain long-lived assets in accordance with provisions of
SFAS No. 121.
25
28
The Company has provided $51.6 million for future liabilities related
to dismantlement and restoration costs which are classified in accumulated DD&A
on the balance sheet at December 31, 1996. Total estimated future dismantlement
and restoration costs of $130.2 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 1996, Selling, General and Administrative ("SG&A") expense increased
$15.1 million over 1995 to $51.6 million. Administrative costs increased $11.1
million in 1996 due to the acquisition of EDC and the hiring of additional
personnel to oversee increased operations. The Company estimates that
approximately 32 percent of the EDC increase is due to non-recurring costs.
INTEREST EXPENSE
1997 VERSUS 1996. During 1997, interest expense increased $14.5 million
from 1996 to $53 million. This increase was due primarily to the indebtedness of
the Company incurred in the financing of the acquisition of EDC. During 1996,
the interest on the EDC acquisition reflects five months costs compared to
twelve months of interest during 1997.
1996 VERSUS 1995. In 1996, interest expense increased $16.6 million
from 1995 to $38.5 million. This increase was due primarily to the financing of
the EDC acquisition offset in part by the conversion into common stock on
November 1, 1996, of the $230,000,000 4 1/4% Convertible Subordinated Notes Due
2003.
MARKETING SUBSIDIARIES
NGM markets the Company's natural gas, as well as certain 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 non-affiliated sales as gathering, marketing and
processing revenues. All intercompany sales and expenses have been eliminated.
NTI markets a portion of the Company's oil, as well as certain
third-party oil. The Company records all of NTI's non-affiliated sales as
gathering, marketing and processing revenues. All intercompany sales and
expenses have been eliminated.
During 1997, NGM recorded $228.4 million in gathering, marketing and
processing revenues and $218.8 million in gathering, marketing and processing
expenses, generating a gross margin of $9.6 million for the year. In 1996, NGM
recorded $197.4 million in gathering, marketing and processing revenues and
$184.6 million in gathering, marketing and processing expenses, generating a
gross margin of $12.8 million for the year. In 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 $4.0 million for
the year.
During 1997, NTI recorded $101.5 million in gathering, marketing and
processing revenues and $95.0 million in gathering, marketing and processing
expenses, generating a gross margin of $6.5 million for the year. In 1996, NTI
recorded $76.3 million in gathering, marketing and processing revenues and $68.9
million in gathering, marketing and processing expenses, generating a gross
margin of $7.4 million for the year. In 1995, NTI began marketing a portion of
the Company's oil as well as certain third-party oil and 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.
FUTURE TRENDS
The Company expects higher production volumes in 1998 compared to 1997.
The increase in volume is expected primarily due to the production associated
with oil and gas properties acquired from New England Energy Incorporated,
effective January 1, 1998, as well as certain new oil and gas properties
expected to commence
26
29
production during the year. Revenue, however, may also be impacted by commodity
prices which are expected to remain volatile during 1998.
The Company has set its 1998 capital budget at approximately $400
million, exclusive of producing property acquisitions. The capital budget
includes the expected 1998 expenditures for the first phase of construction for
the Equatorial Guinea methanol plant and exploration, exploitation and
development expenditures. The Company expects to fund the 1998 capital budget
through its cash flow from operations. The Company will fund the New England
Energy Incorporated property acquisition through short-term borrowings under its
current $300 million credit agreement.
Samedan has from time to time settled various claims against parties
which failed to fulfill their contractual obligation to Samedan to purchase gas
at fixed prices greater than market or pursuant to take-or-pay provisions. The
Company's policy, which is consistent with general industry practice, is that
amounts received in such settlements ("settlement payments") do not represent
payment for gas produced and, therefore, are not subject to royalty payments.
Property owners, including governmental authorities and private parties, have in
recent years asserted claims against Samedan and other oil and gas companies for
royalties on settlement payments.
Samedan participated, in a joint effort with other energy companies and
the Independent Petroleum Association of America ("IPAA"), in a test case which
challenged the determination by the U.S. Minerals Management Service ("MMS")
that royalties were payable to the government on certain settlement payments
received by Samedan (and the other plaintiffs). The District Court for the
District of Columbia (the "D.C. District Court") entered a judgment against
Samedan in the amount of $20,000. In August 1996, the Court of Appeals for the
District of Columbia Circuit reversed the judgment against Samedan. In
subsequent proceedings in the D.C. District Court consistent with the appellate
court decision, on July 25, 1997, the court enjoined the MMS from taking action
to collect from Samedan royalties on non-recoupable settlement payments (the
"MMS Injunction"). The MMS has until April 14, 1998 to appeal the MMS
Injunction.
Notwithstanding the ultimate outcome with respect to the MMS
Injunction, Samedan may be the subject of future legal actions by property
owners claiming royalties on other settlement payments received by Samedan.
There can be no assurance that Samedan will prevail in any such action. The
Company is unable to estimate the possible amount of 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
impact 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 may do so in the
future as a means of controlling its exposure to price changes. The Company
cannot predict the extent to which its operations will be impacted by inflation,
government regulation or changing prices. Market risk is a new disclosure that
the Company is required to report through quantitative and qualitative
disclosures. The required disclosures are presented in the financial statements
and footnotes. For more information concerning market risk, see "Item 8.
Financial Statements and Supplementary Data--Supplemental Oil and Gas
Information (Unaudited)" in this Form 10-K.
The Company is currently in the process of updating its computer
software programs and operating systems so that these systems will properly
utilize dates beyond December 31, 1999. The Company does not expect the cost to
modify its information systems to be material to its financial condition or
results of operations. The Company does not anticipate any material disruptions
in its operations as a result of its year 2000 compliance plan.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Under the general instructions, the Registrant's disclosures about
market risk pursuant to this item should be made in the Registrant's Form 10-K
for the year ending December 31, 1998.
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30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants................................................................ 29
Consolidated Balance Sheet as of December 31, 1997 and 1996............................................. 30
Consolidated Statement of Operations for each of the three years in the period ended
December 31, 1997..................................................................................... 31
Consolidated Statement of Cash Flows for each of the three years in the period ended
December 31, 1997..................................................................................... 32
Consolidated Statement of Shareholders' Equity for each of the three years in the period ended
December 31, 1997..................................................................................... 33
Notes to Consolidated Financial Statements.............................................................. 34
Supplemental Oil and Gas Information (Unaudited)........................................................ 47
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31
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,
1997 and 1996, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1997. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
January 30, 1998
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32
CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES
December 31,
- ---------------------------------------------------------------------------------------------------------------
(In thousands, except share amounts) 1997 1996
- ---------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS:
Cash and short-term cash investments $ 55,075 $ 94,768
Accounts receivable - trade 162,667 206,151
Materials and supplies inventories 2,805 4,489
Other current assets 38,087 11,395
- ---------------------------------------------------------------------------------------------------------------
Total current assets 258,634 316,803
- ---------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 2,766,741 2,536,524
Other 40,286 35,440
- ---------------------------------------------------------------------------------------------------------------
2,807,027 2,571,964
Accumulated depreciation, depletion and amortization (1,260,601) (1,000,200)
- ---------------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 1,546,426 1,571,764
- ---------------------------------------------------------------------------------------------------------------
OTHER ASSETS 70,424 68,371
- ---------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 1,875,484 $ 1,956,938
- ---------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 163,563 $ 143,408
Other current liabilities 28,456 75,736
Current installments of long-term debt 50,000
Income taxes - current 25,001 10,662
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 217,020 279,806
- ---------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES 144,083 108,434
- ---------------------------------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 56,425 50,603
- ---------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 644,967 798,028
- ---------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized;
58,423,438 and 58,321,297 shares issued in 1997 and 1996, respectively 194,743 194,402
Capital in excess of par value 358,054 355,651
Retained earnings 275,610 185,432
- ---------------------------------------------------------------------------------------------------------------
828,407 735,485
Less common stock in treasury, at cost (1997 and 1996, 1,524,900 shares) (15,418) (15,418)
- ---------------------------------------------------------------------------------------------------------------
Total shareholders' equity 812,989 720,067
- ---------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND EQUITY $ 1,875,484 $ 1,956,938
- ---------------------------------------------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
30
33
CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
Year ended December 31,
- ---------------------------------------------------------------------------------------------
(In thousands, except per share amounts) 1997 1996 1995
- ---------------------------------------------------------------------------------------------
REVENUES:
Oil and gas sales and royalties $ 761,145 $ 604,588 $ 328,134
Gathering, marketing and processing 329,868 273,690 112,702
Other income 25,610 8,925 46,182
- ---------------------------------------------------------------------------------------------
Total Revenue 1,116,623 887,203 487,018
- ---------------------------------------------------------------------------------------------
COSTS AND EXPENSES:
Oil and gas exploration 86,698 49,861 33,246
Oil and gas operations 160,765 126,044 81,735
Gathering, marketing and processing 313,807 253,529 107,867
Depreciation, depletion and amortization 300,354 233,604 200,914
Selling, general and administrative 50,545 51,567 36,514
Interest 53,008 38,474 21,871
Interest capitalized (6,239) (2,165) (3,127)
- ---------------------------------------------------------------------------------------------
Total Expenses 958,938 750,914 479,020
- ---------------------------------------------------------------------------------------------
INCOME BEFORE TAXES 157,685 136,289 7,998
INCOME TAX PROVISIONS:
Current 25,569 31,376 (9,123)
Deferred 32,838 21,033 13,035
- ---------------------------------------------------------------------------------------------
Total Tax Provision 58,407 52,409 3,912
- ---------------------------------------------------------------------------------------------
NET INCOME $ 99,278 $ 83,880 $ 4,086
- ---------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 1.75 $ 1.63 $ .08
- ---------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE $ 1.73 $ 1.55 $ .08
- ---------------------------------------------------------------------------------------------
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 56,872 51,414 50,046
Diluted 57,421 57,223 50,466
- ---------------------------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
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34
CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
Year ended December 31,
- -------------------------------------------------------------------------------------------------------
(In thousands) 1997 1996 1995
- -------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 99,278 $ 83,880 $ 4,086
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 300,354 233,604 200,914
Amortization of undeveloped leasehold costs, net 8,146 5,827 6,465
(Gain) loss on disposal of assets (11,007) (3,335) (3,289)
Noncurrent deferred income taxes 35,650 38,989 7,642
Increase in other deferred credits 5,822 14,409 14,194
(Increase) decrease in other 1,684 (16,296) (399)
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable 43,484 (89,141) (29,786)
(Increase) decrease in other current assets (25,053) 10,608 5,151
Increase (decrease) in accounts payable (29,845) 37,536 27,063
Increase (decrease) in other current liabilities 17,058 64,864 6,879
- -------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 445,571 380,945 238,920
- -------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (326,958) (257,719) (255,188)
Acquisition of Energy Development Corporation (768,185)
Proceeds from sale of property, plant and equipment 54,543 26,758 10,745
- -------------------------------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (272,415) (999,146) (244,443)
- -------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Exercise of stock options 2,744 7,851 3,766
Cash dividends paid (9,100) (8,311) (8,006)
Proceeds from bank borrowings 800,000 30,000
Repayment of bank debt (549,000) (99,000) (30,000)
Proceeds from issuance of long-term debt 342,507
- -------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (212,849) 700,540 (4,240)
- -------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS (39,693) 82,339 (9,763)
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 94,768 12,429 22,192
- -------------------------------------------------------------------------------------------------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 55,075 $ 94,768 $ 12,429
- -------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 46,140 $ 28,652 $ 17,659
Income taxes $ 32,415 $ 11,500 $
See accompanying Notes to Consolidated Financial Statements.
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35
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
Capital in Treasury
Common Stock Excess of Stock at Retained
(In thousands, except shares issued) Shares Issued Amount Par Value Cost Earnings
- ------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1995 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) $109,863
- ------------------------------------------------------------------------------------------------------------------
Net Income 83,880
Exercise of stock options 323,140 1,077 6,774
Redemption of convertible notes 6,275,510 20,918 203,818
Cash dividends ($ .16 per share) (8,311)
- ------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1996 58,321,297 $194,402 $355,651 $(15,418) $185,432
- ------------------------------------------------------------------------------------------------------------------
Net Income 99,278
Exercise of stock options 102,141 341 2,403
Cash dividends ($.16 per share) (9,100)
- ------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997 58,423,438 $194,743 $358,054 $(15,418) $275,610
- ------------------------------------------------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements.
33
36
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, 1997.
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 of North Africa, Inc.
Samedan LPG
Samedan Methanol
Samedan Pipe Line Corporation
Samedan Royalty Corporation
Samedan of Tunisia, Inc.
Energy Development Corporation ("EDC")
Brabant Petroleum Limited
EDC Argentina, Inc.
EDC Australia, Ltd.
EDC China, Inc.
EDC Ecuador Ltd.
EDC HIPS, Inc.
EDC Portugal Ltd.
EDC Senegal Ltd.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, 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 international operations with production in Argentina,
Equatorial Guinea and the U.K. Sector of the North Sea. 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.
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37
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 Canada is the Canadian dollar which has been translated into U.S. dollars
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 ("DD&A") expense over the productive
lives of the related properties. The Company has provided $59.5 million for such
future costs classified with accumulated DD&A in the balance sheet. The total
estimated future dismantlement and restoration costs of $143.9 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 holding period. Geological and geophysical
costs, delay rentals and costs to drill exploratory wells which do not find
proved reserves are expensed. Repairs and maintenance are charged to expense as
incurred.
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.
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.
BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 128 "Earnings per Share" in February 1997. The
Company adopted disclosure requirements of SFAS No. 128 during 1997 and restated
all previously presented financial statements in conformity with SFAS No. 128.
Basic income per share of common stock has been computed on the basis of the
weighted average number of shares outstanding during each period. The diluted
net income per share of common stock includes the effect of outstanding stock
options and the dilutive effect of the convertible subordinated notes, which
were converted on November 1, 1996.
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38
The following table summarizes the calculation of basic earnings per
share ("EPS") and diluted EPS as of December 31:
1997 1996 1995
------------------------------ -------------------------- ---------------------------
Income Shares Income Shares Income Shares
(shares in thousands) (Numerator) (Denominator) (Numerator) (Denominator) (Numerator) (Denominator)
- ---------------------------------------------------------------------------------------------------------------------
Net income/shares $99,278 56,872 $83,880 51,414 $4,086 50,046
- ---------------------------------------------------------------------------------------------------------------------
BASIC EPS $1.75 $1.63 $.08
- ---------------------------------------------------------------------------------------------------------------------
Net income/shares $99,278 56,872 $83,880 51,414 $4,086 50,046
Effect of Diluted Securities
Stock options 549 556 420
4 1/4% Convertible
Subordinated Notes (1) 4,692 5,253
-----------------------------------------------------------------------------------------
Adjusted net income
and shares $99,278 57,421 $88,572 57,223 $4,086 50,466
- ---------------------------------------------------------------------------------------------------------------------
DILUTED EPS $1.73 $1.55 $.08
- ---------------------------------------------------------------------------------------------------------------------
(1) In 1995, the 4 1/4% Convertible Subordinated Notes were
anti-dilutive and were converted on November 1, 1996.
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 and EDC have a gas sales contract with NGM, whereby Samedan and
EDC are 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, EDC 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 $21.6 million and
$21.7 million for 1997 and 1996, 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 $18.5 million and
$19.3 million for 1997 and 1996, respectively, and are valued at the amount
which is expected to be received.
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39
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 subsidiaries, from time to time, uses various
hedging arrangements in connection with anticipated crude oil and natural gas
sales of its production to minimize the impact of product price fluctuations.
Such arrangements include fixed price hedges, costless collars and other
contractual arrangements. Although these hedging arrangements expose the Company
to credit risk, the Company monitors the creditworthiness of its counterparties,
which generally are major institutions, and believes that losses from
nonperformance are unlikely to occur. Hedging gains and losses related to the
Company's oil and gas production are recorded in oil and gas sales and
royalties.
During 1997, the Company had natural gas hedging contracts that ranged
from 20 percent to 32 percent of its average daily natural gas production.
Natural gas hedges were in the price range of $1.88 to $3.30 per million British
Thermal Units ("MMBTU"). The net effect of these 1997 hedges was a $.12 per
thousand cubic feet ("MCF") reduction in the average natural gas price realized
by the Company. At December 31, 1997, the Company had no natural gas hedging
contracts.
During 1997, the Company had crude oil hedging contracts that ranged
from 19 percent to 50 percent of its average daily oil production. Crude oil
hedges were in the price range of $16.81 to $24.35 per barrel ("BBL"). The net
effect of these 1997 hedges was a $.19 per BBL reduction in the average crude
oil price realized by the Company. At December 31, 1997, the Company had no
crude oil hedging contracts.
During 1996, the Company had natural gas hedging contracts that ranged
from 39 percent to 86 percent of its average daily natural gas production.
Natural gas hedges were in the price range of $1.60 to $3.59 per MMBTU. The net
effect of these 1996 hedges was a $.33 per MCF reduction in the average natural
gas price. At December 31, 1996, the Company was a party to natural gas hedging
contracts to hedge approximately 21 percent of its estimated 1997 average daily
natural gas production at an average price per MMBTU of $2.20.
During 1996, the Company had crude oil hedging contracts that ranged
from 48 percent to 55 percent of its average daily oil production for January
through July and 62 percent to 100 percent of its average daily oil production
for August through December. Crude oil hedges were in the price range of $16.50
to $24.27 per BBL. The net effect of these 1996 hedges was a $2.35 per BBL
reduction in the average crude oil price. At December 31, 1996, the Company was
a party to crude oil hedging contracts to hedge approximately 26 percent of its
estimated 1997 annual crude oil production at an average price per BBL of
$20.48.
During 1995, Samedan had natural gas hedging contracts for November and
December to hedge from 20 percent to 46 percent of its average daily natural gas
production. For May to December 1995, Samedan had hedged approximately 20
percent of its daily crude oil production. Natural gas hedges were in the range
of $1.60 to $1.96 per MMBTU and crude oil hedges were in the range of $18.56 to
$20.27 per BBL. The net effect of these 1995 hedges was a $.004 per MCF
reduction in the average natural gas price and a $.16 per BBL increase in the
average crude oil price realized by the Company.
In addition to the hedging arrangements pertaining to the Company's
production as described above, NGM employs various hedging arrangements in
connection with its purchases and sales of third party production to lock in
profits or limit exposure to gas price risk. Most of the purchases made by NGM
are on an index basis; however, purchasers in the markets in which NGM sells
often require fixed or New York Mercantile Exchange ("NYMEX") related pricing.
NGM may use a hedge to convert the fixed or NYMEX sale to an index basis thereby
determining the
37
40
margin and minimizing the risk of price volatility. During 1997, NGM had hedging
transactions with broker-dealers that ranged from 317,693 MMBTU's to 768,599
MMBTU's of gas per day.
At December 31, 1997, NGM had in place hedges ranging from
approximately 645 MMBTU's to 29,279 MMBTU's of gas per day for January 1998 to
March 1999 for future physical transactions. At December 31, 1996, NGM had in
place hedges ranging from approximately 7,475 MMBTU's to 551,126 MMBTU's of gas
per day for January 1997 to March 1998 for future physical transactions. 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. 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.
SELF-INSURANCE
The Company self-insures the medical and dental coverage provided to certain of
its employees, certain workers' compensation and the first $200,000 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 1996 and 1995
consolidated financial statements to conform to the 1997 presentation.
RECENTLY ISSUED PRONOUNCEMENTS
In December 1997, the Financial Accounting Standards Board issued SFAS
No. 130 "Reporting Comprehensive Income" and SFAS No. 131 "Disclosures About
Segments of an Enterprise and Related Information." The Company plans on
adopting both SFAS No. 130 and No. 131 in 1998. The Company anticipates there
will be no material impact associated with the adoption of these standards.
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.
38
41
The carrying amounts and estimated fair values of the Company's
financial instruments as of December 31, for each of the years are as follows:
1997 1996
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------------------------------------
Cash and short-term cash investments $ 55,075 $ 55,075 $ 94,768 $ 94,768
Oil and gas hedge agreements $ 5,180 $ (26,869)
Long-term debt (including current portion) $ 644,967 $ 740,000 $ 848,028 $ 854,000
NOTE 3 - DEBT
A summary of debt at December 31 follows:
1997 1996
- --------------------------------------------------------------------------------------------------------------
$800 million Credit Agreement $ $749,000
$300 million Credit Agreement 200,000
7 1/4% Notes Due 2023 100,000 100,000
8% Senior Notes Due 2027 250,000
7 1/4% Senior Debentures Due 2097 100,000
- --------------------------------------------------------------------------------------------------------------
Outstanding debt 650,000 849,000
- --------------------------------------------------------------------------------------------------------------
Less: current portion 50,000
Less: unamortized discount 5,033 972
- --------------------------------------------------------------------------------------------------------------
Long-term debt $ 644,967 $798,028
- --------------------------------------------------------------------------------------------------------------
Total long-term debt at December 31, 1997, was $645 million compared to
$848 million (including current portion) at December 31, 1996, a decrease of 24
percent. The ratio of debt to book capital (defined as the Company's debt plus
its equity) was 44 percent at December 31, 1997, compared with 54 percent at
December 31, 1996.
The $300 million credit agreement is a revolving credit facility with a
group of banks with a final maturity of December 24, 2002. The interest rate
charged, which is based upon a Eurodollar rate plus 22.5 basis points, was 5.9
percent at December 31, 1997. Financial covenants include maintenance of a cash
flow multiple of at least four times interest cost and maintenance of a debt
level which does not exceed 60 percent of the Company's shareholders' equity
plus its debt.
The $800 million credit agreement was terminated on December 24, 1997,
and the outstanding balance of $200 million was refinanced in the $300 million
credit agreement. The weighted average interest rate on the borrowings during
1997 was 6.9 percent.
Total long-term debt outstanding at December 31, 1997, included $100
million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, and
$100 million of 7 1/4 % Senior Debentures Due 2097.
The only principal payment on long-term debt due during the next five
years is the outstanding balance of the $300 million credit agreement on
December 24, 2002.
On November 1, 1996, all of the Company's $230 million 4 1/4%
Convertible Subordinated Notes Due 2003 were converted into 6,275,510 shares of
common stock.
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42
NOTE 4 - INCOME TAXES
The components of income from operations before income taxes for each
year are as follows:
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Domestic $159,535 $137,462 $ 18,368
Foreign (1,850) (1,173) (10,370)
- --------------------------------------------------------------------------------------------------------------
$157,685 $136,289 $ 7,998
- --------------------------------------------------------------------------------------------------------------
The income tax provisions relating to operations for each year consist of the
following:
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
U.S. current $22,146 $ 26,425 $(9,309)
U.S. deferred 34,344 17,918 11,327
State current 587 844 65
State deferred (622) 644 258
Foreign current 2,836 4,107 121
Foreign deferred (884) 2,471 1,450
- --------------------------------------------------------------------------------------------------------------
$58,407 $ 52,409 $ 3,912
- --------------------------------------------------------------------------------------------------------------
The following table details the difference between the federal
statutory tax rate and the effective tax rate for the years ended December 31:
(Amounts expressed in percentages) 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Statutory rate 35.0 35.0 35.0
Effect of:
Percentage depletion (.1) (.1) (1.4)
State taxes .7 2.6
Foreign taxes .8 3.1 12.8
Losses from international operations 1.4 .1
Other, net (.1) (.3) (.1)
- --------------------------------------------------------------------------------------------------------------
Effective rate 37.0 38.5 48.9
- --------------------------------------------------------------------------------------------------------------
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43
The net current deferred tax asset (liability) in the following table
is classified as Other Current Assets in the Consolidated Balance Sheet at
December 31, 1997 and 1996. The tax effects of temporary differences which gave
rise to deferred tax assets and liabilities as of December 31 were:
1997 1996
- --------------------------------------------------------------------------------------------------------------
U.S. and State Current Deferred Tax Assets:
Accrued expenses $ (2,269) $ (197)
Deferred income 3,127 255
Deferred hedge (219)
Minimum tax 286
Allowance for doubtful accounts 496 1,186
Other 903 (111)
- --------------------------------------------------------------------------------------------------------------
Net current deferred tax asset 2,257 1,200
- --------------------------------------------------------------------------------------------------------------
U.S. and State Non-current Deferred Tax Liabilities:
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments (138,771) (100,983)
Accrued expenses 4,390 3,454
Deferred income 6,351 6,629
Income tax accruals 10,688 11,215
Other 1,548 423
- --------------------------------------------------------------------------------------------------------------
Net non-current deferred liability (115,794) (79,262)
- --------------------------------------------------------------------------------------------------------------
U.S. and state net deferred tax liability (113,537) (78,062)
- --------------------------------------------------------------------------------------------------------------
Foreign Deferred Tax Liabilities:
Property, plant and equipment of
foreign operations (28,289) (25,226)
Valuation allowance (3,946)
- --------------------------------------------------------------------------------------------------------------
Deferred tax liability (28,289) (29,172)
- --------------------------------------------------------------------------------------------------------------
Total deferred taxes $ (141,826) $ (107,234)
- --------------------------------------------------------------------------------------------------------------
A valuation allowance of $3.9 million for 1996 related to the Company's
foreign operations was established for the portion of the deferred tax assets
which management believed unlikely to have a tax benefit realized. The valuation
allowance for 1996 was related to Canada and was written off in 1997 due to the
sale of the Company's Canadian assets.
NOTE 5 - COMMON STOCK, STOCK OPTIONS AND STOCKHOLDER RIGHTS
The Company has two stock option plans, the 1992 Stock Option and
Restricted Stock Plan ("1992 Plan") and the 1988 Non-Employee Director Stock
Option Plan ("1988 Plan"). The Company accounts for these plans under APB
Opinion 25, under which no compensation cost has been recognized in the
accompanying financial statements.
Under the Company's 1992 Plan, the Board of Directors may grant stock
options and award restricted stock. No restricted stock has been issued under
the 1992 Plan. Since the 1992 Plan's adoption, stock options have been issued at
the market price on the date of grant. The earliest the granted 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 1992 Plan was amended in 1997, with a vote of the
shareholders, to increase the maximum number of shares of common stock that may
be issued under the 1992 Plan to 4,000,000 shares. At December 31, 1997, the
Company had reserved 3,735,166 shares of common stock for issuance, including
1,850,282 shares available for grant under its 1992 Plan.
The Company's 1988 Plan allows stock options to be issued to certain
non-employee directors 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
1988 Plan provides for the grant of options to purchase a maximum of 550,000
shares of the Company's authorized but unissued common stock. At December 31,
1997, the Company had reserved 433,000 shares of common stock for issuance,
including 274,000 shares available for grant under its 1988 Plan.
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44
Stock options outstanding under the plans mentioned above and two
previously terminated plans are presented for the periods indicated.
Number Option
of Shares Price Range
- ---------------------------------------------------------------------------------------------------------------
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
Canceled (18,144) $16.88-$27.25
- ---------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1995 1,583,709 $10.63-$30.00
- ---------------------------------------------------------------------------------------------------------------
Granted 376,368 $37.63-$40.38
Exercised (323,140) $10.63-$27.25
Canceled (34,839) $16.88-$27.25
- ---------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1996 1,602,098 $10.63-$40.38
- ---------------------------------------------------------------------------------------------------------------
Granted 707,307 $39.63-$39.88
Exercised (102,141) $10.63-$40.38
Canceled (1,929) $24.25-$27.25
- ---------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1997 2,205,335 $11.63-$40.38
- ---------------------------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 1997 1,158,175 $11.63-$40.38
- ---------------------------------------------------------------------------------------------------------------
The following schedule shows the Company's net income and net income
per share for each of the years ended December 31, had compensation costs been
determined consistent with SFAS No. 123 "Accounting for Stock-Based
Compensation."
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Net Income:
As Reported $99,278 $83,880 $4,086
Pro Forma $90,874 $82,447 $3,651
Basic Earnings Per Share:
As Reported $ 1.75 $ 1.63 $ .08
Pro Forma $ 1.60 $ 1.60 $ .07
Diluted Earnings Per Share:
As Reported $ 1.73 $ 1.55 $ .08
Pro Forma $ 1.58 $ 1.44 $ .07
The SFAS No. 123 method of accounting is not required to be applied to
options granted prior to 1995. The pro forma information presented above is
based on several assumptions and should not be viewed as indicative of the
operations of the Company in future periods.
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following weighted-average
assumptions used for grants in 1997, 1996 and 1995, respectively:
(Amounts expressed in percentages) 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Interest rate 6.03 6.62 6.33
Dividend yield .40 .40 .66
Expected volatility 32.97 32.89 33.33
The weighted average fair value of options granted using the
Black-Scholes option model for 1997, 1996 and 1995, respectively:
(Amounts expressed in dollars) 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Black-Scholes model weighted average fair value
option price $18.28 $18.95 $11.05
42
45
The Company adopted a stockholder rights plan on August 27, 1997,
designed to assure that the Company's stockholders receive fair and equal
treatment in the event of any proposed takeover of the Company and to guard
against partial tender offers and other abusive takeover tactics to gain control
of the Company without paying all stockholders a fair price. The rights plan was
not adopted in response to any specific takeover proposal. Under the rights
plan, the Company declared a dividend of one right ("Right") on each share of
Noble Affiliates, Inc. Common Stock. Each Right will entitle the holder to
purchase one one-hundredth of a share of a new Series A Junior Participating
Preferred Stock, par value $1.00 per share, at an exercise price of $150.00. The
Rights are not currently exercisable and will become exercisable only in the
event a person or group acquires beneficial ownership of 15 percent or more of
Noble Affiliates, Inc. Common Stock. The dividend distribution was made on
September 8, 1997, to stockholders of record at the close of business on that
date. The Rights will expire on September 8, 2007.
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.
The periodic pension expense included the following components for the
years ended December 31:
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Service cost-benefits earned in the period $ 3,003 $ 2,212 $ 1,781
Interest cost on projected benefit obligation 4,078 3,382 3,298
Actual return on plan assets (10,060) (6,734) (8,611)
Net amortization and deferral 6,917 3,621 5,461
- --------------------------------------------------------------------------------------------------------------
Net pension expense $ 3,938 $ 2,481 $ 1,929
- --------------------------------------------------------------------------------------------------------------
43
46
The funded status of the Company's pension plans at December 31 was as
follows:
1997 1996
---------------------- ----------------------
Funded Unfunded Funded Unfunded
- --------------------------------------------------------------------------------------------------------------
Actuarial present value of:
Vested benefit obligation $ 31,350 $ 4,202 $ 27,694 $ 3,473
Accumulated benefit
obligation 35,939 4,586 31,476 3,623
- --------------------------------------------------------------------------------------------------------------
Projected benefit obligation 52,134 10,353 42,506 5,074
Plan assets at fair value 55,611 47,921
- --------------------------------------------------------------------------------------------------------------
Plan assets in excess of
(less than) projected
benefit obligation 3,477 (10,353) 5,415 (5,074)
Unrecognized net (gain) loss (12,486) 4,287 (11,775) 32
Unrecognized net (asset)
liability at transition (1,721) 3,009 (1,936) 3,248
Unrecognized prior
service cost 2,608 521 2,579 451
- --------------------------------------------------------------------------------------------------------------
Accrued pension cost $ (8,122) $ (2,536) $ (5,717) $(1,343)
- --------------------------------------------------------------------------------------------------------------
The Company's assumptions as of December 31 in determining the pension cost and
liability for the three years were as follows:
(Amounts expressed in percentages) 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Discount rate 7.25 7.75 7.25
Rates of increase in compensation 5.50 5.50 5.50
Long-term rate of return on plan assets 8.50 8.50 8.50
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. The Company may match up
to 100 percent of the participant's contribution not to exceed six percent of
the employee's base compensation. Plan contributions of $1,369,000, $1,053,000
and $895,000 for 1997, 1996 and 1995, 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, 7.75 and 7.25 percent in 1997, 1996 and 1995,
respectively. The health care cost trend rate was assumed to be nine percent for
1997, declining by one percent for three successive years to six percent in 2000
and 2001, decreasing to five 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, 1997, would have increased approximately $352,000. The effect of this change
on the aggregate of service and interest cost for 1997 would have been an
increase of approximately $55,000.
44
47
Net postretirement benefit cost included the following components for
the years ended December 31:
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Service cost-benefits earned in the period $210 $180 $140
Interest cost-accumulated benefit obligation 154 143 123
Net loss amortization 14 27 12
- --------------------------------------------------------------------------------------------------------------
Net postretirement benefit cost $378 $350 $275
- --------------------------------------------------------------------------------------------------------------
The plan's postretirement benefit obligation at December 31 was as
follows:
1997 1996
- --------------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ (143) $ (357)
Fully eligible active employees (272) (377)
Active employees, not fully eligible (1,969) (1,418)
- --------------------------------------------------------------------------------------------------------------
Total participants (2,384) (2,152)
Plan assets
- --------------------------------------------------------------------------------------------------------------
Funded status (2,384) (2,152)
Unrecognized net loss 455 554
- --------------------------------------------------------------------------------------------------------------
Accrued postretirement benefit obligation $ (1,929) $(1,598)
- --------------------------------------------------------------------------------------------------------------
NOTE 7 - EDC ACQUISITION
On July 31, 1996, Samedan acquired all the outstanding shares of common
stock of EDC for $768 million. The acquisition has been accounted for using the
purchase method of accounting. Accordingly, the purchase price has been
allocated to EDC's assets and liabilities based on fair values at the date of
the acquisition.
The operating results of EDC have been included in the Consolidated
Statement of Operations from the date of the acquisition. The pro forma
information includes adjustments for interest expense that would have been
incurred to finance the acquisition, additional depreciation, depletion and
amortization based on the fair value of EDC's property, plant and equipment and
expected savings from the termination of certain EDC employees and facilities
consolidation.
The following information has been prepared assuming the acquisition
had taken place at the beginning of 1996 and 1995:
Pro Forma
-----------------------------------
(unaudited) 1996 1995
- ----------------------------------------------------------------------------------------------------------------
Revenues $ 1,103,334 $842,757
Net income $ 74,082 $ 73
Basic earnings per share $ 1.44 $ 0.00
Diluted earnings per share $ 1.29 $ 0.00
The pro forma information presented above is based on several
assumptions and should not be viewed as indicative of the operations of the
Company in future periods.
45
48
NOTE 8 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Included in accounts receivable-trade is an allowance for doubtful
accounts at December 31 of the following:
1997 1996
- --------------------------------------------------------------------------------------------------------------
Allowance for doubtful accounts $ 1,401 $3,083
Other current assets at December 31 include the following:
1997 1996
- --------------------------------------------------------------------------------------------------------------
Deferred hedges $ $1,684
Deferred tax asset $ 2,257 $1,200
Other current liabilities at December 31 include the following:
1997 1996
- --------------------------------------------------------------------------------------------------------------
Gas imbalance liabilities $4,153 $3,583
Oil and gas operations expense included the following for the years
ended December 31:
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Lease operating expense $ 151,712 $ 116,692 $78,959
Production taxes $ 11,947 $ 10,108 $ 3,426
Oil and gas exploration expense included the following for the years
ended December 31:
1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Dry hole expense $46,902 $ 32,762 $17,608
Undeveloped lease amortization $ 8,146 $ 5,827 $ 6,465
Abandoned assets $ 4,923 $ 545 $ 483
Seismic $19,095 $ 11,885 $ 8,358
During the past three years, there was no purchaser that accounted for
more than ten percent of total oil and gas sales and royalties.
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. This impairment included $3.2 million in
Tunisia, $4.1 million in Canada, $18.4 million onshore U.S., and $33.8 million
offshore Gulf of Mexico properties.
The Company recorded no asset impairment under SFAS No. 121 for its
properties during 1997 and 1996.
46
49
SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
PROVED OIL AND GAS RESERVES (Unaudited)
The following reserve schedule was 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.
Natural Gas and Crude Oil & Condensate
Casinghead Gas (MMCF) (BBLS in thousands)
--------------------------------------- --------------------------------------
PROVED RESERVES AS OF: United States International(1) TOTAL United States International(1) TOTAL
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1994 744,245 34,705 778,950 65,536 9,991 75,527
- -----------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates (35,728) (4,776) (40,504) 247 (517) (270)
Extensions, discoveries and
other additions 143,589 6,558 150,147 12,270 3,658 15,928
Production (94,038) (2,946) (96,984) (8,175) (1,405) (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 1,380 2,524
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995 818,301 32,038 850,339 70,907 13,101 84,008
- -----------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates (30,618) (2,792) (33,410) (187) 731 544
Extensions, discoveries and
other additions 127,399 9,825 137,224 7,701 2,507 10,208
Production (162,996) (5,104) (168,100) (10,785) (2,287) (13,072)
Sale of minerals in place (49,851) (4,286) (54,137) (1,239) (216) (1,455)
Purchase of minerals in place 377,372 46,962 424,334 15,920 19,594 35,514
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1996 1,079,607 76,643 1,156,250 82,317 33,430 115,747
- -----------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates (1,228) (1,110) (2,338) 1,516 865 2,381
Extensions discoveries and
other additions 226,546 329,230 555,776 16,501 15,211 31,712
Production (195,085) (7,551) (202,636) (11,450) (3,024) (14,474)
Sale of minerals in place (6,934) (22,299) (29,233) (184) (4,797) (4,981)
Purchase of minerals in place 4,252 144 4,396 365 113 478
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997 1,107,158 375,057 1,482,215 89,065 41,798 130,863
- -----------------------------------------------------------------------------------------------------------------------
(1) The December 31, 1997, proved reserves for the Company's
international operations are detailed as follows:
Proved Reserves Equatorial Guinea Argentina United Kingdom Total
-----------------------------------------------------------------------------------------------------
Oil (thousand BBLS) 22,767 11,997 7,034 41,798
Gas (MMCF) 322,204 5,565 47,288 375,057
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.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves. Oil and gas reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
precisely measured, and estimates of engineers other than Samedan's might differ
materially from the estimates set forth herein. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing and
production subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the quantities
of oil and gas that are ultimately recovered.
47
50
PROVED DEVELOPED OIL AND GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve
engineers and set forth the changes in estimated quantities of proved developed
oil and gas reserves of the Company presented as of the beginning of each year.
Natural Gas and Crude Oil & Condensate
Casinghead Gas (MMCF) (BBLS in thousands)
--------------------------------------- --------------------------------------
PROVED DEVELOPED RESERVES: United States International(1) TOTAL United States International(1) TOTAL
- -----------------------------------------------------------------------------------------------------------------------
January 1, 1995 658,228 34,705 692,933 63,013 8,305 71,318
January 1, 1996 750,753 32,036 782,789 67,368 11,667 79,035
January 1, 1997 1,010,837 50,258 1,061,095 78,564 29,334 107,898
January 1, 1998 1,022,192 66,279 1,088,471 82,713 29,422 112,135
Proved Developed Reserves. Proved developed reserves are proved
reserves which are expected to be recovered through existing wells with existing
equipment and operating methods.
COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)
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.
1997 1996 1995
------------------------------- -------------------------------- ------------------------------
U.S. Int'l TOTAL U.S. Int'l TOTAL U.S. Int'l TOTAL
- ---------------------------------------------------------------------------------------------------------------------
Property acquisition
costs:
Proved $ 3,884 $ 28 $ 3,912 $ 541,363 $ 146,052 $ 687,415 $ 36,728 $ 6,932 $ 43,660
Unproved 16,668 3,178 19,846 24,672 21,737 46,409 8,209 1,096 9,305
- ---------------------------------------------------------------------------------------------------------------------
Total $ 20,552 $ 3,206 $ 23,758 $ 566,035 $ 167,789 $ 733,824 $ 44,937 $ 8,028 $ 52,965
- ---------------------------------------------------------------------------------------------------------------------
Exploration
costs $ 81,141 $ 36,023 $ 117,164 $ 81,018 $ 9,981 $ 90,999 $ 39,008 $ 11,586 $ 50,594
- ---------------------------------------------------------------------------------------------------------------------
Development
costs $ 201,788 $ 14,180 $ 215,968 $ 176,419 $ 7,886 $ 184,305 $ 159,405 $ 2,981 $ 162,386
- ---------------------------------------------------------------------------------------------------------------------
AGGREGATE CAPITALIZED COSTS (Unaudited)
Aggregate capitalized costs relating to the Company's oil and gas
producing activities, and related accumulated DD&A, as of December 31:
1997 1996
------------------------------------- --------------------------------------
U. S. Int'l TOTAL U. S. Int'l TOTAL
- -------------------------------------------------------------------------------------------------------------------
Unproved oil and gas properties $ 57,666 $ 7,190 $ 64,856 $ 49,380 $ 26,591 $ 75,971
Proved oil and gas properties 2,473,989 227,896 2,701,885 2,242,325 218,228 2,460,553
- -------------------------------------------------------------------------------------------------------------------
2,531,655 235,086 2,766,741 2,291,705 244,819 2,536,524
Accumulated DD&A (1,201,446) (36,338) (1,237,784) (943,055) (33,778) (976,833)
- ------------------------------------------------------------------------------------------------------ ------------
Net capitalized costs $ 1,330,209 $ 198,748 $1,528,957 $1,348,650 $211,041 $1,559,691
- -------------------------------------------------------------------------------------------------------------------
48
51
OIL AND GAS OPERATIONS (Unaudited)
Aggregate results of operations for each period ended December 31, in
connection with the Company's oil and gas producing activities are shown below.
1997 1996 1995
----------------------------- ------------------------------ ------------------------------
U.S. Int'l TOTAL U.S. Int'l TOTAL U.S. Int'l TOTAL
- ----------------------------------------------------------------------------------------------------------------------
Revenues $696,882 $64,263 $761,145 $548,488 $56,100 $604,588 $301,710 $26,424 $328,134
Production costs 164,441 22,153 186,594 118,387 20,737 139,124 74,911 7,473 82,384
Exploration
expenses 56,177 24,555 80,732 43,844 15,473 59,317 40,971 12,262 53,233
DD&A and valuation
provision 280,862 21,967 302,829 222,426 13,767 236,193 191,227 13,115 204,342*
- ----------------------------------------------------------------------------------------------------------------------
Income (loss) 195,402 (4,412) 190,990 163,831 6,123 169,954 (5,399) (6,426) (11,825)
Income tax
expense (benefit) 67,934 (183) 67,751 57,873 4,850 62,723 (2,046) (2,296) (4,342)
- ----------------------------------------------------------------------------------------------------------------------
Results of operations
from producing
activities (excluding
corporate overhead
and interest costs) $127,468 $(4,229) $123,239 $105,958 $ 1,273 $107,231 $ (3,353) $ (4,130) $(7,483)
- ------------------------------------------------------------------------------------------------------------- --------
*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 (Unaudited)
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 as of December 31, 1997, 1996 and 1995 as 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.
1997 1996 1995
---------------------------- -------------------------------- ---------------------------
(in millions of dollars) U.S. Int'l TOTAL U.S. Int'l TOTAL U.S. Int'l TOTAL
- ---------------------------------------------------------------------------------------------------------------------
Future cash inflows $4,330 $ 953 $5,283 $ 6,013 $878 $6,891 $3,610 $ 277 $ 3,887
Future production and
development costs 2,040 330 2,370 2,078 361 2,439 1,055 58 1,113
Future income tax
expenses 612 166 778 1,078 147 1,225 709 61 770
- ---------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,678 457 2,135 2,857 370 3,227 1,846 158 2,004
10% annual discount for
estimated timing of
cash flows 615 168 783 890 115 1,005 673 57 730
- ---------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $1,063 $ 289 $1,352 $ 1,967 $255 $2,222 $1,173 $ 101 $ 1,274
- ---------------------------------------------------------------------------------------------------------------------
The future net cash inflows for 1997 do not include cash flows relating
to the Company's anticipated future methanol sales. For more information
regarding Samedan's methanol plant, see Item 1. and Item 2. "Business--Oil and
Gas" of this Form 10-K.
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 $16.22 per BBL.
49
52
West Texas intermediate crude oil price in mid February 1998 was
approximately $2.72 per BBL lower than year-end 1997. The Company estimates that
a $1.00 per BBL change in the average oil price from the year-end price would
change discounted future net cash flows before income taxes by approximately $74
million.
The year-end weighted average gas price utilized in the computation of
future cash inflows was approximately $2.55 per MCF. Natural gas index prices at
Henry Hub have decreased approximately $.33 per MCF in mid February 1998
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 $83 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 costs
and exploration expenses of ongoing operations relating to the Company's proved
oil and gas reserves.
At December 31, 1997, the Company had estimated gas imbalance
receivables of $18.5 million and estimated liabilities of $21.6 million; at
year-end 1996, $19.3 million in receivables and $21.7 million in liabilities;
and at year-end 1995, $12.3 million in receivables and $11.4 million in
liabilities. Neither the gas imbalance receivables nor liabilities have been
included in the standardized measure of discounted future net cash flows as of
each of the three years ended December 31, 1997, 1996 and 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.
(In millions of dollars) 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the beginning
of the year $ 2,222 $ 1,274 $ 736
Extensions, discoveries and improved
recovery, less related costs 501 256 378
Revisions of previous quantity estimates 13 (76) (53)
Changes in estimated future
development costs (15) (21) (29)
Purchases/sales of minerals in place (45) 1,043 116
Net changes in prices and production costs (1,259) 212 378
Accretion of discount 310 178 103
Sales of oil and gas produced, net of
production costs (594) (475) (241)
Development costs incurred during
the period 38 74 67
Net change in income taxes 332 (368) (216)
Change in timing of estimated future
production, and other (151) 125 35
- --------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the end
of the year $ 1,352 $ 2,222 $1,274
- --------------------------------------------------------------------------------------------------------------
50
53
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 1997 and
1996 are as follows:
Quarter Ended
--------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31,(1)
- --------------------------------------------------------------------------------------------------------------
1997
Revenues $ 322,455 $ 236,667 $ 234,349 $ 323,153
Gross profit
from operations $ 74,625 $ 32,596 $ 34,694 $ 62,539
Net income $ 38,363 $ 13,152 $ 15,177 $ 32,586
Basic earnings per share $ .67 $ .23 $ .27 $ .57
Diluted earnings per share $ .67 $ .23 $ .26 $ .57
1996
Revenues $ 170,423 $ 183,572 $ 235,933 $ 297,275
Gross profit
from operations $ 40,410 $ 31,066 $ 37,333 $ 63,789
Net income $ 22,679 $ 16,859 $ 15,306 $ 29,036
Basic earnings per share $ .45 $ .33 $ .31 $ .53
Diluted earnings per share $ .43 $ .32 $ .29 $ .51
(1) During the fourth quarter of 1997 and 1996, DD&A expense increased $5.5
million and $.8 million, respectively, relating to the cumulative effect of
oil and gas reserve revisions on the DD&A provision for the preceding three
quarters.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
51
54
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The section entitled "Election of Directors" in the Registrant's proxy
statement for the 1998 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 "Section 16(a) Beneficial Ownership Reporting
Compliance" in the Registrant's proxy statement for the 1998 annual meeting of
stockholders sets forth certain information with respect to compliance with
Section 16(a) of the Securities Exchange Act of 1934, as amended, and is
incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The section entitled "Executive Compensation" in the Registrant's proxy
statement for the 1998 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 and Stock
Option Committee of the Board of Directors and the information therein under
"Executive Compensation--Performance Graph" is incorporated herein by reference.
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" in the Registrant's
proxy statement for the 1998 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.
The section entitled "Certain Transactions" in the Registrant's proxy
statement for the 1998 annual meeting of stockholders sets forth certain
information with respect to certain relationships and related transactions, and
is incorporated herein by reference.
52
55
PART IV
ITEM 14. FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
(1) Financial Statements and Financial Statement Schedules: These
documents are listed in the Index to Consolidated Financial
Statements in Item 8 hereof.
(2) 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, 1997.
53
56
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 16, 1998 By: /s/ William D. Dickson
----------------------------
William D. Dickson,
Senior 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 16, 1998
- ------------------------------------ Chief Executive Officer and
Robert Kelley Director (Principal Executive
Officer)
/s/ William D. Dickson Senior Vice President-Finance and March 16, 1998
- ------------------------------------ Treasurer (Principal Financial Officer)
William D. Dickson
/s/ James L. McElvany Vice President and Controller March 16, 1998
- ------------------------------------ (Principal Accounting Officer)
James L. McElvany
/s/ Alan A. Baker Director March 16, 1998
- ------------------------------------
Alan A. Baker
/s/ Michael A. Cawley Director March 16, 1998
- ------------------------------------
Michael A. Cawley
/s/ Edward F. Cox Director March 16, 1998
- ------------------------------------
Edward F. Cox
/s/ James C. Day Director March 16, 1998
- ------------------------------------
James C. Day
/s/ Harold F. Kleinman Director March 16, 1998
- ------------------------------------
Harold F. Kleinman
/s/ George J. McLeod Director March 16, 1998
- ------------------------------------
George J. McLeod
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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 year ended December 31, 1987 and incorporated
herein by reference).
3.2 -- Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant dated
August 27, 1997 (filed Exhibit A of Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A
filed on August 28, 1997 and incorporated herein by reference).
3.3 -- Amendments of Articles III and VI of the Bylaws of the Registrant adopted February 3, 1998.
3.4 -- Composite copy of Bylaws of the Registrant as currently in effect.
4.1 -- 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%
Notes 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).
4.2 -- Indenture relating to Senior Debt Securities dated as of April 1, 1997 between the Registrant and U.S.
Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.1 to the Registrant's Quarterly Report on
Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference).
4.3 -- First Indenture Supplement relating to $250 million of the Registrant's 8% Senior Notes Due 2027 dated
as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as
Exhibit 4.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and
incorporated herein by reference).
4.4 -- Second Indenture Supplement, between the Company and U.S. Trust Company of Texas, N.A. as trustee,
relating to $100 million of the Registrant's 7 1/4% Senior Debentures Due 2097 dated as of August 1,
1997 (filed as Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June
30, 1994 and incorporated herein by reference).
10.1* -- Samedan Oil Corporation Bonus Plan, as amended and restated on September 24, 1996 (filed as Exhibit 10.1
to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1996 and
incorporated herein by reference).
10.2* -- 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 year ended December 31, 1994 and incorporated herein by reference).
10.3* -- Noble Affiliates Thrift Restoration Plan dated May 9, 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).
10.4* -- 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).
10.5* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as amended and restated, dated
November 2, 1992 (filed as Exhibit 4.1 to the Registrant's Registration Statement on Form S-8
(Registration No. 33-54084) and incorporated herein by reference).
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58
Exhibit
Number Exhibit **
- ------- -------
10.6* -- 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1 to the Registrant's Registration Statement
on Form S-8 (Registration No. 2-81590) and incorporated herein by reference).
10.7* -- Amendment No. 1 to the 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.2 to the
Registrant's Registration Statement on Form S-8 (Registration No. 2-81590) and incorporated herein by
reference).
10.8* -- Amendment No. 2 to the 1982 Stock Option Plan of the Registrant (filed as Exhibit 10.11 to the
Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 and incorporated herein by
reference).
10.9* -- 1978 Non-Qualified Stock Option Plan of the Registrant (filed as Exhibit 1.1 to the Registrant's
Registration Statement on Form S-8 (Registration No. 2-64600) and incorporated herein by reference).
10.10* -- 1978 Non-Qualified Stock Option Plan of the Registrant, as amended July 27, 1978 (filed as Exhibit 1.2
to the Registrant's Registration Statement on Form S-8 (Registration No. 2-64600) and incorporated
herein by reference).
10.11* -- Amendment No. 2 to the 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).
10.12* -- Amendment No. 3 to the 1978 Non-Qualified Stock Option Plan of the Registrant (filed as Exhibit 10.15 to
the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 and incorporated herein
by reference).
10.13* -- 1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended and
restated, effective as of January 30, 1996 (filed as Exhibit 10.13 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1996 and incorporated herein by reference).
10.14* -- Form of Indemnity Agreement entered into between the Registrant and each of the Registrant's directors
and bylaw officers (filed as Exhibit 10.18 to the Registrant's Annual Report of Form 10-K for the year
ended December 31, 1995 and incorporated herein by reference).
10.15 -- 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).
10.16 -- Stock Purchase Agreement dated as of July 1, 1996, between Samedan Oil Corporation and Enterprise
Diversified Holdings Incorporated (filed as Exhibit 2.1 to the Registrant's Current Report on Form
8-K (Date of Event: July 31, 1996) dated August 13, 1996 and incorporated herein by reference).
10.17 -- Credit Agreement dated as of July 31, 1996 among the Registrant, as borrower, certain commercial lending
institutions which are or may become a party thereto, as lenders (filed as Exhibit 10.1 to the
Registrant's Current Report on Form 8-K (Date of Event: July 31, 1996), filed on August 13, 1996 and
incorporated herein by reference).
10.18 -- First Amendment to Credit Agreement dated as of October 15, 1996 among the Registrant, as borrower,
certain commercial lending institutions which are or may become parties thereto, as lenders, and Union
Bank of Switzerland, Houston Agency, as agents for the lender (filed as Exhibit 4.2 to the Registrant's
Registration Statement on Form S-3 (No. 333-14275) and incorporated herein by reference).
56
59
Exhibit
Number Exhibit **
- ------- -------
10.19* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as amended and restated on December
10, 1996, subject to the approval of stockholders (filed as Exhibit 10.21 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1996 and incorporated herein by reference).
10.20 -- Amended and Restated Credit Agreement dated as of December 24, 1997 among the Registrant, as borrower,
and Union Bank of Switzerland, Houston agency, as the agent for the lender, and NationsBank of Texas,
N.A. and Texas Commerce Bank National Association, as managing agents, and Bank of Montreal, CIBC Inc.,
The First National Bank of Chicago, Royal Bank of Canada, and Societe Generale, Southwest agency, as
co-agents, and certain commercial lending institutions, as lenders.
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.
** Copies of exhibits will be furnished upon prepayment of 25 cents
per page. Requests should be addressed to the Senior Vice President
- Finance and Treasurer, Noble Affiliates, Inc., Post Office Box
1967, Ardmore, Oklahoma 73402.
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