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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
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, 1998
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)
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<S> <C>
Delaware 73-0785597
(State of incorporation) (I.R.S. employer identification number)
</TABLE>
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:
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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.
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
-----
Aggregate market value of Common Stock held by nonaffiliates as of
February 12, 1999: $1,095,000,000.
Number of shares of Common Stock outstanding as of February 12, 1999:
56,981,008.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 1999
Annual Meeting of Stockholders to be held on April 27, 1999, which will be
filed with the Securities and Exchange Commission within 120 days after
December 31, 1998, are incorporated by reference into Part III.
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TABLE OF CONTENTS
PART I.
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Item 1. Business......................................................... 1
General.......................................................... 1
Oil and Gas...................................................... 2
Exploration Activities....................................... 2
Production Activities ....................................... 4
Acquisitions of Oil and Gas Properties, Leases and
Concessions.................................................. 5
Marketing.................................................... 5
Regulations and Risks........................................ 6
Competition.................................................. 7
Unconsolidated Subsidiary........................................ 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....... 30
Item 8. Financial Statements and Supplementary Data...................... 31
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................. 56
PART III.
Item 10. Directors and Executive Officers of the Registrant............... 56
Item 11. Executive Compensation........................................... 56
Item 12. Security Ownership of Certain Beneficial Owners and Management... 56
Item 13. Certain Relationships and Related Transactions................... 56
PART IV.
Item 14. Financial Statement Schedules, Exhibits and Reports on Form 8-K.. 56
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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, projected
timing of planned projects or activities, 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,
and 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")
and million British Thermal Units ("MMBTU"). Equivalent units are expressed in
thousand cubic feet of gas equivalents ("MCFe"), million cubic feet of gas
equivalents ("MMCFe"), billion cubic feet of gas equivalents ("BCFe"), or
trillion cubic feet of gas equivalents ("TCFe"), converting oil to gas at one
barrel of oil equaling six thousand cubic feet of gas, or barrel of oil
equivalents ("BOE") converting gas to oil at six thousand cubic feet of gas to
one barrel of oil.
The Company's wholly owned subsidiary, NGM, markets the majority of
the Company's natural gas as well as third-party gas. 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 NGM's operations and NTI's
operations, see "Item 1. Business--Oil and Gas--Marketing" of this Form 10-K.
The Company owns a 45 percent interest in Atlantic Methanol Production
Company ("AMPCO"), an unconsolidated subsidiary accounted for on the equity
method. For more information, see "Item 1. Business--Unconsolidated Subsidiary"
of this Form 10-K.
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OIL AND GAS
The Company's wholly owned subsidiary, Samedan, directly or through
various arrangements with other companies, investigates potential oil and gas
properties, seeks to acquire exploration rights in areas of interest and
conducts exploration activities. Exploration activities include geophysical and
geological evaluation and exploratory drilling on properties for which the
Company has exploration rights. Samedan has been engaged in the exploration,
production and marketing of oil and gas since 1932. Samedan has exploration,
exploitation and production operations domestically and internationally. The
domestic areas consist of: offshore in the Gulf of Mexico; the Gulf Coast area
(Louisiana, New Mexico and Texas); the Mid Continent region (Oklahoma and
Southern Kansas); and the Rocky Mountain division (Colorado, Montana, North
Dakota, Wyoming and California). The international areas of operations include
Argentina, China, Denmark, Ecuador, Equatorial Guinea, the Mediterranean Sea,
the North Sea and the United Kingdom. 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.
In January 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 for 1996 and 1997. There were no Canadian
operations in 1998.
In January 1998, the Registrant acquired all the oil and gas
properties of New England Energy Incorporated, a wholly owned subsidiary of New
England Energy Systems, for $50 million. The consolidated financial statements
of the Registrant (Item 8. of this Form 10-K) include the revenues and
expenditures associated with these properties for the entire year.
Exploration Activities
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 220 wells operated by Samedan and 364 wells operated by others. During the
past 30 years, Samedan has drilled or participated in the drilling of 894 gross
wells in the Gulf of Mexico. At December 31, 1998, the Company held offshore
federal leases covering 1,059,443 gross developed acres and 996,017 gross
undeveloped acres in the Gulf of Mexico on which the Company currently intends
to conduct future exploration activities. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
Gulf Coast Area. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties in the Gulf Coast area
(onshore Louisiana, New Mexico and Texas) since the 1930's. The Company's
current production in the Gulf Coast area is derived from 636 wells operated by
Samedan and 1,484 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, 1998, the
Company held 177,132 gross developed acres and 157,733 gross undeveloped acres
in the Gulf Coast area on which the Company currently intends to conduct future
exploration activities. For more information, see "Item 2. Properties--Oil and
Gas" of this Form 10-K.
Mid Continent Region. 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
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current oil and gas production in the Mid Continent region is derived from 517
wells operated by Samedan and 1,449 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, 1998, the Company held 260,042 gross developed acres and 98,928
gross undeveloped acres in the Mid Continent region on which the Company
currently intends to conduct future exploration activities. For more
information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
Rocky Mountain Division. 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 784 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,
1998, the Company held 338,845 gross developed acres and 245,698 gross
undeveloped acres in the Rocky Mountain division on which it currently intends
to conduct future exploration activities. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
Argentina. Samedan, through its subsidiary EDC Argentina, Inc., has
been actively engaged in exploration, exploitation and development of oil and
gas properties in Argentina since 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. At December 31,
1998, the Company held 28,988 gross developed acres and 84,337 gross
undeveloped acres in Argentina, with an expiration date of 2016, on which the
Company currently intends to conduct future exploration activities. For more
information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
China. Samedan, through its subsidiary EDC China, Inc., has been
actively engaged in exploration, exploitation and development of oil and gas
properties in China since 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, 1998, the Company held 307,398
gross undeveloped acres in China, on which the Company currently intends to
conduct future exploration activities. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
Ecuador. Samedan, through its subsidiary EDC Ecuador Ltd., has been
actively engaged in exploration, exploitation 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 but had never been developed due to the lack of a gas market
and infrastructure in Ecuador. The concession, Block 3, which covers 864,126
gross acres and encompasses the Amistad field, was awarded to EDC in 1996 by
the Ecuadorian government. For more information, see "Item 2. Properties--Oil
and Gas" of this Form 10-K.
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 condensate and has a
sizable gas reserve which will be utilized as feedstock by a methanol plant
currently under construction. The plant will be owned by AMPCO in which the
Company owns a 45 percent interest. For more information on the methanol plant,
see "Item 1. Business--Unconsolidated Subsidiary" of this Form 10-K. Based on
reserve estimates, the Alba field can deliver gas sufficient for the plant to
operate for 30 years. At December 31, 1998, the Company held 26,651 gross
developed acres and 285,307 gross undeveloped acres offshore Equatorial Guinea,
on which the Company currently intends to conduct future exploration
activities. For more information, see "Item 2. Properties--Oil and Gas" of this
Form 10-K.
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United Kingdom and the North Sea. Samedan, through its subsidiary EDC
(Europe) Limited (formerly Brabant Petroleum Limited), has been actively
engaged in exploration, exploitation and development of oil and gas properties
in the United Kingdom and the North Sea since 1996. The Company's current oil
and gas production in the United Kingdom and the North Sea is derived from 130
wells operated by others. Reservoirs in the North Sea tend to have the same
attributes as Gulf of Mexico reservoirs. At December 31, 1998, the Company held
130,876 gross developed acres and 396,885 gross undeveloped acres on which the
Company currently intends to conduct future exploration activities. For more
information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
Denmark. In 1998, Samedan, through its subsidiary EDC Denmark, was
awarded an 80 percent interest in the offshore Denmark license 13/98 comprising
Block 5505/09 and the southwest portion of Block 5505/05. The license
encompasses 80,900 acres with water depths ranging from 115 feet to 180 feet.
For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
Mediterranean Sea. In 1998, the Company, through its subsidiary
Samedan, Mediterranean Sea, Inc., entered into a participation agreement, with
a 40 percent interest, covering nine licenses encompassing 885,625 gross acres.
The acreage is located about 20 miles offshore Israel in water depths ranging
from 2,500 feet to 5,000 feet. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
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:
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1998 1997 1996
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(In percentages) Oil Gas Oil Gas Oil Gas
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Operated well count basis 20.7 58.9 15.1 60.8 22.4 57.4
Operated sales volume basis 45.3 59.2 48.8 63.5 56.6 68.3
</TABLE>
Net Production. The following table sets forth Samedan's net oil and
natural gas production including royalty, for the three years ended December 31:
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1998 1997 1996
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Oil Production
(million BBLS) 13.6 14.0 12.6
Gas Production
(BCF) 206.8 206.4 171.8
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Oil and Gas Equivalents. The following table sets forth Samedan's net
production stated in oil and gas equivalent volumes, for the three years ended
December 31:
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1998 1997 1996
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<S> <C> <C> <C>
Total Oil Equivalents
(million BOE) 48.1 48.4 41.3
Total Gas Equivalents
(BCFe) 288.4 290.4 247.6
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Acquisitions of Oil and Gas Properties, Leases and Concessions
During 1998, Samedan spent approximately $48.4 million on the purchase
of producing oil and gas properties. Samedan spent approximately $3.9 million
on producing properties in 1997 and approximately $687 million in 1996 related
to the EDC acquisition. For more information, see "Item 2. Properties--Oil and
Gas" of this Form 10-K.
During 1998, Samedan spent approximately $37.4 million on acquisitions
of unproved properties. These properties were acquired primarily through
domestic onshore lease acquisitions, various offshore lease sales and
international concession negotiations. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
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 1998, approximately 60 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 short-term gas sales contracts with NGM, whereby
Samedan and EDC are paid an index price for all gas sold to NGM. Samedan and
EDC sold 50.2 percent of their production to NGM in 1998. 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. The Company has a small number of long-term gas contracts
representing less than five percent of its total gas sales.
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 by
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 $17.86 per BBL in 1997 to $11.66 per BBL in
1998. Due to the volatility of oil prices, the Company, from time to time, has
used derivative hedging and may do so in the future as a means of controlling
its exposure to price changes. For additional information, see "Item 8.
Financial Statements and Supplementary Data" of this Form 10-K.
Substantial competition in the natural gas marketplace continued in
1998. Gas prices, which were once determined largely by governmental
regulations, are now being influenced to a greater extent by the marketplace.
The Company's average gas price decreased from $2.48 per MCF in 1997 to $2.18
per MCF in 1998. Due to the volatility of gas prices, the Company, from time to
time, has used derivative hedging and may do so in the future as a means of
controlling its exposure to price changes. For additional information, see
"Item 8. Financial Statements and Supplementary Data" of this Form 10-K.
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The largest single non-affiliated purchaser of the Company's oil in
1998 was Plains Marketing, Inc., which accounted for approximately 37 percent
of the Company's oil sales, representing 9.2 percent of total revenues. The
five largest purchasers accounted for approximately 76 percent of total oil
sales. The largest single non-affiliated purchaser of the Company's gas in 1998
accounted for approximately two percent of its gas sales. The five largest
purchasers accounted for approximately nine 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, 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.
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, the Company is subject to various federal, state, local and
foreign country laws and regulations relating to the discharge of materials
into, and the protection of, the environment. The release or discharge of oil
from Samedan's domestic onshore or offshore facilities could subject Samedan to
liability under federal laws and regulations, including the Oil Pollution Act
of 1990, the Outer Continental Shelf Lands Act and the Clean Water Act, for
pollution cleanup costs, damage to the environment, civil or criminal
penalties, and orders or injunctions requiring the suspension or cessation of
operations in affected areas. The liability under these laws for a substantial
release or discharge of oil, subject to certain specified limitations on
liability, may be extraordinarily large. If any oil pollution was caused by
willful misconduct, willful negligence or gross negligence, or was caused
primarily by a violation of federal regulations, such limitations on liability
may not apply. Certain of Samedan's facilities are subject to regulations of
the United States Environmental Protection Agency, including regulations that
require the preparation and implementation of spill prevention control and
countermeasure plans relating to the possible discharge of oil into navigable
water.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as "Superfund", imposes liability on certain classes
of persons that contributed to the release or threatened release of a hazardous
substance into the environment or that own or operate facilities or vessels
onto or into which hazardous substances are disposed. The Resource Conservation
and Recovery Act ("RCRA") and regulations promulgated thereunder regulate
hazardous waste, including its treatment, storage and disposal. CERCLA
currently exempts crude oil, and RCRA currently exempts certain oil and gas
exploration and production drilling materials, such as drilling fluids and
produced waters, from the definitions of hazardous substances and hazardous
wastes. Samedan's operations, however, may involve the use or handling of other
materials that may be classified as hazardous substances and hazardous wastes,
and therefore, these statutes and regulations promulgated under them would
apply
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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.
UNCONSOLIDATED SUBSIDIARY
The Company owns a 45 percent interest in AMPCO and accounts for its
interest on the equity method within Samedan Methanol. For more information,
see "Item 8. Financial Statements and Supplementary Data" of this Form 10-K.
Samedan is participating in AMPCO with a 50 percent expense interest (45
percent ownership and a five percent government carried interest) to construct
a methanol plant in Equatorial Guinea. The total projected cost of the plant
and supporting facilities is estimated to be $423.8 million. The plant is being
designed to produce 2,500 metric tons of methanol per day, which equates to
approximately 20,000 BBLS per day. At this level of production, the plant would
use approximately 120 MMCF of gas per day from Samedan's 34.8 percent owned
Alba field as feedstock. Reserve estimates indicate the Alba field can deliver
sufficient gas for the plant to operate 30 years. The construction contract
stipulates that first production of methanol should be achieved by the first
quarter of 2001. Current marketing plans are to seek to enter into long-term
contracts with methanol users in the United States and Europe.
EMPLOYEES
During the year, the total number of employees of the Company
increased from 614 at December 31, 1997 to 630 at December 31, 1998.
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ITEM 2. PROPERTIES.
OFFICES
The principal executive office of the Registrant is located in
Ardmore, Oklahoma. 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 oil and gas operations; one for international operations, one for
offshore operations and one for onshore operations. NGM's office is located in
Houston, Texas and NTI's office is located in Ardmore, Oklahoma.
OIL AND GAS
Samedan, directly or through various arrangements with others,
searches for potential oil and gas properties, seeks to acquire exploration
rights in areas of interest and conducts exploratory activities. These
activities include geophysical and geological evaluation and exploratory
drilling, where appropriate, on properties for which it acquired exploration
rights. During 1998, Samedan drilled or participated in the drilling of 187
gross (88.1 net) wells, comprised of 29 gross (4.4 net) international wells and
158 gross (83.7 net) domestic wells. 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 1998, Samedan drilled or
participated in the drilling of 61 gross wells, of which 25 were exploratory
wells (10.4 net) and 36 were development wells (17.0 net) in federal and state
waters offshore Texas and Louisiana. Of the 61 gross wells, 41 wells (18.4 net)
were completed as productive and 20 wells (9.1 net) were abandoned as dry
holes. Samedan was high bidder on 30 tracts in the two federal lease sales
during the year and was awarded 28 new leases, of which 12 are located in water
depths greater than 1,000 feet. Samedan was also the successful bidder on 16
tracts located in the state waters offshore Texas. The Company intends to
remain active in these areas of the Gulf of Mexico.
In 1998, the Company drilled and completed two 100 percent owned wells
on its High Island A-550 Block, offshore Texas. The wells were completed in the
second quarter and at year end were producing approximately 60 MMCF of gas and
2,000 BBLS of condensate per day.
In the first quarter, Samedan commenced production from its Main Pass
261 property, in which it owns a 50 percent working interest. The field, which
contains four wells, was producing 43 MMCF of gas and 650 BBLS of condensate
per day at year end.
Production commenced in the second quarter of 1998 from Samedan's 25
percent owned East Cameron 381 field, located offshore Louisiana. At year end,
the field was producing approximately 60 MMCF of gas and 3,700 BBLS of
condensate per day from three wells.
Samedan made an apparent discovery at Vermilion 335 and 336. The 335
#2 well (50 percent working interest) logged 72 feet of pay in one zone. The
336 A-1 well (33.3 percent working interest) logged 45 feet of pay in two
zones. The wells should be completed and start production in the third quarter
of 1999.
Gas production commenced from the Company's 66.7 percent owned South
Timbalier 220 property in the third quarter of 1998. The field was producing
approximately 24 MMCF of gas per day at year end.
Samedan participated with an 8.2 percent working interest in drilling
six wells and completing five wells in the West Cameron 498 field. The field
was producing approximately 2,500 BBLS of oil and 15 MMCF of gas per day at
year end.
8
<PAGE> 11
Samedan kept a drilling rig busy for most of the year in its 100
percent owned Main Pass 305/306 oil field. The Company completed three wells on
the "E" platform and drilled and completed three wells on the "A" platform
during 1998. When oil prices recover, the Company intends to do additional
drilling in the field on the "B" and "D" platforms, which have seven possible
drilling locations identified.
A gas discovery on Grand Isle 58 was being developed at year end. The
well logged 49 feet of pay and is expected to be connected to the sales line in
the first quarter of 1999. The Company owns a 30 percent working interest in
the well, which is projected to commence production at a rate of 17 MMCF of gas
per day.
During 1999, the Company expects to participate in two deepwater
exploration wells. The first well is anticipated to be drilled on Ewing Bank
995, Sidewinder prospect, located offshore Louisiana. The well, in which the
Company has a 42.5 percent working interest, is targeted to be drilled to
18,000 feet and will be located in approximately 1,060 feet of water. The
second deepwater exploratory well is anticipated to be drilled on Green Canyon
238, Cleopatra prospect, located offshore Louisiana. The well, in which the
Company will pay a 40 percent interest to earn a 20 percent interest in the
lease, is targeted to be drilled to 25,800 feet and will be located in
approximately 2,150 feet of water. The Company may proceed with drilling other
deepwater prospects it has in inventory or acquires through farm-in during the
year. Such activity will depend on available cash flow and industry conditions.
Gulf Coast Area. During 1998, Samedan participated in drilling 12 gas
wells in the Caspiana prospect in north Louisiana with interests ranging from
6.4 to 39.2 percent. The wells are completed in the Cotton Valley formation and
have typical initial production rates of .6 to 2.1 MMCF of gas per day. Samedan
anticipates that six to eight additional wells will be drilled in north
Louisiana during 1999.
The best onshore gas discovery drilled by the Company in 1998 was in
the Javelina prospect located in Starr County, Texas. The Chevron-BTLT #1 well
was drilled to 11,570 feet and encountered approximately 218 feet of Vicksburg
gas pay in two zones. The lower zone, 56 feet of pay, was abandoned due to
mechanical difficulties. The upper zone, 162 feet of pay, was fracture treated
and completed at the rate of 5.5 MMCF of gas per day and 102 BBLS of oil per
day. Samedan owns a 45 percent working interest in the well and in
approximately 6,000 gross acres on the prospect. The Company expects to drill
four additional wells offsetting the discovery in 1999. Samedan also made a gas
discovery in the Vicksburg formation eight miles south of the Chevron-BTLT #1
well in the S.W. Jeffress prospect. The Yturria #1 well encountered
approximately 100 feet of Vicksburg gas pay between the depths of 8,360 feet
and 8,730 feet. The well is waiting on pipeline connection and fracture
treatment. The Company owns a 37.5 percent interest in the well and in 3,146
surrounding acres and expects to participate in three additional wells on the
prospect in 1999.
In south Louisiana, the A.R. Romaine #2 was drilled to approximately
15,200 feet and completed in the Marg Howei formation. The well was completed
at the initial rate of 15 MMCF of gas and 376 BBLS of condensate per day.
Samedan owns a 35.6 percent working interest in the well. At year end, Samedan
was recompleting the Romero #3 well in the Kaplan field to the Marg Howei
formation. Based upon offset well performance, Samedan projects the well will
be capable of producing 14 MMCF of gas and 350 BBLS of condensate per day.
Samedan owns an 81.4 percent working interest in the well.
Rocky Mountain Division. The area with the most active drilling
program was the Niobrara play in Yuma County, Colorado. Samedan participated in
21 gas wells with interests ranging from 12.5 to 100 percent. Samedan owns an
interest in approximately 72,700 gross acres in the area and estimates that 90
additional locations remain to be drilled.
Argentina. The Company participated with a 13.7 percent working
interest in 25 exploitation wells drilled in the El Tordillo field during the
year. The field is producing approximately 2,300 BBLS of oil per day, net to
the Company's interest. The 1999 budget proposed by the field operator consists
of ten exploitation wells and an exploratory well to be drilled within five
miles of the existing field.
9
<PAGE> 12
China. The Company drilled two wells on its Cheng Dao Xi concession,
located in the southern portion of the Bo Hai Bay during 1998. The 18-1 well
encountered approximately 154 feet of oil pay in 12 sands, as determined from
electric logs. Five of the zones were perforated and flowed at the combined
rate of approximately 1,500 BBLS of oil per day. The 19-1 well encountered
approximately 59 feet of oil pay in three sands. Two lower sands were tested at
the combined flow rate of approximately 120 BBLS of oil per day. The uppermost
sand was not tested due to testing of the zone by the Chinese on previous wells
drilled on the concession. The zone flowed at the rate of approximately 450
BBLS of oil per day during such test. Samedan has submitted an overall field
development plan ("ODP") to the appropriate Chinese agencies for approval. The
ODP sets forth various development scenarios and expenditures, as well as
economic projections. Subsequent to approval of the ODP, the costs will be
shared 57 percent by the Company and 43 percent by the Chinese National
Petroleum Corporation. During 1999, Samedan may drill an additional well on the
Cheng Dao Xi concession and exploratory wells on the Cheng Zi Kou concession
and on the Getuo concession. Due to low worldwide oil prices such drilling
activities may be delayed if approved by the Chinese authorities.
Ecuador. The Company owns a 100 percent working interest in the Block
3 concession, located offshore Ecuador in the Gulf of Guayaquil. The concession
includes 864,126 acres and encompasses the Amistad gas field. During the year,
Samedan supplemented its 3-D seismic grid on the field with 272 additional
miles of 2-D seismic data. The Company is working on a joint venture
arrangement which would include a comprehensive plan to develop the Amistad
field and supply gas to a new electric power generation plant to be constructed
simultaneously with field development. The field development is expected to
take approximately 24 months and encompass fabrication and installation of a
platform, production facilities and pipeline, as well as drilling and
completing four wells. Platform construction is anticipated to commence mid
year 1999.
Equatorial Guinea. The Company owns a 45 percent interest in AMPCO,
which is constructing a methanol plant in Equatorial Guinea. The plant is
designed to produce 2,500 metric tons of methanol per day, which is the
equivalent of 20,000 BBLS per day. The turnkey construction contract of $313.5
million stipulates that production of methanol should be achieved in the first
quarter of 2001. During 1999, the Company anticipates it will make
approximately $85.4 million in progress payments toward the plant construction.
For additional information, see "Item 1. Business--Unconsolidated Subsidiary"
of this Form 10-K.
The Company drilled an additional well in its Alba gas and condensate
field during the year. The Alba #5 well was drilled approximately 13,000 feet
southwest of the two existing producing wells. It encountered approximately 325
feet of gas and condensate in one pay zone, as determined from electric logs;
the well was not tested. Current exploitation plans for the field include
installing a platform, drilling three additional wells and constructing a
pipeline. Upon completion of the exploitation plan, which is expected to take
20 months, the field should be capable of producing approximately 250 MMCF of
gas and 17,000 BBLS of condensate per day. Approximately 120 MMCF of gas per
day will be sold to the methanol plant as feedstock with the balance reinjected
into the reservoir. The Company owns a 34.8 percent working interest in the
Alba field and in 285,307 gross undeveloped surrounding acres.
North Sea. Gas production commenced from Samedan's 24 percent owned
Malory field in the fourth quarter of 1998. At year end, the field was
producing approximately 70 MMCF of gas per day. The Company participated with a
12.5 percent interest in a successful well on its Goldeneye prospect on Block
20/4b. The well tested 41.5 MMCF of gas and 2,055 BBLS of condensate per day.
Development of the Goldeneye prospect will most likely require unitization with
the offset acreage, which is operated by Shell.
During 1998, Samedan was awarded Blocks 28/15 and 29/11 in the 18th
round of licensing. Samedan owns a 45 percent interest in the blocks, which are
located in the central North Sea.
Denmark. The Company was awarded an 80 percent working interest in
license 13/98, located offshore Denmark. The license encompasses 80,900 acres
with water depths ranging from 115 to 180 feet.
10
<PAGE> 13
Mediterranean Sea. The Company has entered into an exploration
participation agreement offshore Israel. The agreement covers nine licenses
encompassing 885,625 acres. The acreage is located approximately 20 miles
offshore in water depths ranging from 2,500 to 5,000 feet. Samedan anticipates
a rig will be on location early in the second quarter of 1999. The exploratory
well is targeted to be drilled to 7,250 feet and cost an estimated $9.4
million. The well will test a gas prospect that has been delineated by recent
seismic data. The initial prospect size is estimated to be 200 to 250 BCF of
gas. The Company will pay a 53.3 percent interest in the well to earn a 40
percent interest in the licenses.
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.
<TABLE>
<CAPTION>
Net Exploratory Wells Net Development Wells
---------------------------------------- ----------------------------------------
Productive(1) Dry(2) Productive(1) Dry(2)
---------------------------------------- ----------------------------------------
Year Ended
December 31, U.S. Int'l U.S. Int'l U.S. Int'l U.S. Int'l
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 15.63 .13 15.16 .33 42.21 3.92 10.71
1997 13.98 .76 25.08 3.79 155.93 3.13 7.89
1996 15.37 .69 22.16 1.04 74.97 1.17 19.91
</TABLE>
- -----------------
(1) A productive well is an exploratory or a development well that is not a
dry hole.
(2) A dry hole is an exploratory or development well found to be incapable
of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
At January 12, 1999, Samedan was drilling seven gross (2.9 net)
exploratory wells and nine gross (2.9 net) development wells. These wells are
located onshore in the United States in California, Louisiana, Montana,
Oklahoma and Texas, and offshore Gulf of Mexico. These wells have objectives
ranging from approximately 6,500 to 18,000 feet. The estimated drilling cost to
Samedan of these wells is approximately $5.5 million if all are dry and
approximately $7.7 million if all are completed as producing wells.
11
<PAGE> 14
Oil and Gas Wells. The number of productive oil and gas wells in which
Samedan held an interest as of December 31, were as follows:
<TABLE>
<CAPTION>
1998(1)(3) 1997(1)(2)(3) 1996(1)(3)
-------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
OIL WELLS
United States - Onshore 4,571.5 895.8 4,614.5 881.4 4,607.0 860.8
United States - Offshore 344.0 145.9 327.0 140.3 343.0 151.1
International 1,019.0 119.2 549.0 58.5 629.0 91.8
- -------------------------------------------------------------------------------------------------------------------
Total 5,934.5 1,160.9 5,490.5 1,080.2 5,579.0 1,103.7
- -------------------------------------------------------------------------------------------------------------------
GAS WELLS
United States - Onshore 1,608.5 944.7 1,568.5 920.9 1,476.0 847.2
United States - Offshore 410.0 152.2 480.0 176.6 530.0 186.9
International 25.0 2.0 25.0 1.9 89.0 32.6
- -------------------------------------------------------------------------------------------------------------------
Total 2,043.5 1,098.9 2,073.5 1,099.4 2,095.0 1,066.7
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Productive wells are producing wells and wells capable of production. A
gross well is a well in which a working interest is owned. The number
of gross wells is the total number of wells in which a working interest
is owned. A net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The number of
net wells is the sum of the fractional working interests owned in gross
wells expressed as whole numbers and fractions thereof.
(2) 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.
(3) One or more completions in the same bore hole is counted as one well in
this table. The following table summarizes multiple completions and
non-producing wells as of December 31 for the years shown. Included in
wells not producing are productive wells awaiting additional action,
pipeline connections or shut-in for various reasons.
<TABLE>
<CAPTION>
1998 1997 1996
-------------------------------------------------------------------------
Gross Net Gross Net Gross Net
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
MULTIPLE COMPLETIONS
Oil 21.5 15.5 24.5 18.1 21.0 14.4
Gas 47.5 24.7 48.5 21.6 47.0 23.6
NOT PRODUCING (SHUT-IN)
Oil 1,609.5 237.2 1,017.0 127.3 1,086.0 136.7
Gas 58.5 23.2 79.5 50.1 63.5 32.0
</TABLE>
At year-end 1998, Samedan had less than five percent of its oil and
gas sales volumes committed to long-term supply contracts and had no similar
agreements with foreign governments or authorities in which Samedan acts as
producer.
Since January 1, 1998, 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 ("EIA"). Samedan files Form 23, including reserve and other
information, with the EIA.
12
<PAGE> 15
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.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1998 1997 1996
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Average sales price per BBL of oil (1):
United States $ 11.98 $18.49 $ 17.83
International $ 10.28 $15.55 $ 20.32
Combined (2) $ 11.66 $17.86 $ 18.28
Average sales price per MCF of natural gas (1):
United States $ 2.18 $ 2.48 $ 2.18
International $ 2.13 $ 2.29 $ 1.90
Combined (3) $ 2.18 $ 2.48 $ 2.17
Average production (lifting) cost per unit of oil and
natural gas production, excluding depreciation
(MCFe)(4):
United States $ .52 $ .58 $ .49
International $ .66 $ .85 $ 1.04
Combined $ .54 $ .61 $ .53
</TABLE>
- ------------
(1) Net production amounts used in this calculation include royalties.
(2) Reflects a reduction of $.19 per BBL in 1997 and $2.35 per BBL in 1996
from hedging.
(3) Reflects a reduction of $.12 per MCF in 1997 and $.33 per MCF in 1996
from hedging.
(4) Oil production is converted to gas equivalents (MCFe) 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
(BBLS to MCF) for 1998, 1997 and 1996 are set forth below:
<TABLE>
<CAPTION>
United States International
------------- -------------
<S> <C> <C>
1998 .18 to 1 .21 to 1
1997 .13 to 1 .15 to 1
1996 .12 to 1 .09 to 1
</TABLE>
13
<PAGE> 16
SIGNIFICANT OFFSHORE UNDEVELOPED LEASE HOLDINGS (interests rounded to
nearest whole percent)
<TABLE>
<CAPTION>
Net Working Net Working Net Working Net Working
Block Interest (%) Block Interest(%) Block Interest (%) Block Interest(%)
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
East Breaks Eugene Island South Timbalier Garden Banks
420* 50 84 95 98 50 25 100
421* 50 300 67 156 67 34 100
464* 50 317 67 219 67 35 100
465* 50 323 50 Ewing Bank 62 25
475* 100 South Marsh Island 993 50 63 25
519* 100 62 67 995 43 64 25
563* 100 63 67 996 43 78 100
588* 100 65 67 Vermilion 107 25
632* 100 104 100 278 50 116 100
633* 100 167 100 280 50 122 100
Green Canyon 179 35 283 50 154 100
23* 50 180 35 285 50 163 100
24* 43 185 35 286 100 326* 100
25* 43 186 35 300 50 534* 35
27* 43 191 50 312 100 536* 35
85* 50 Mississippi Canyon 345 75 537* 35
227* 50 524* 50 349 75 538* 35
228* 50 573 100 360 67 578* 35
238* 20 583* 50 361 67 580* 35
Galveston 618* 50 365 50 581* 35
249-L 50 661* 25 366 75 582* 35
250-L 50 665* 50 377 100 625* 35
274-L 50 705* 25 394 75 751* 100
275-L 50 West Cameron High Island 795* 100
340-S 50 583 100 A-426 33 841* 40
341-S 50 602 100 A-435 33 Viosca Knoll
349-S 50 Brazos South Pass 344 100
Ship Shoal 336-L 50 41 50 820 50
313 40 337-L 50
</TABLE>
*Located in water deeper than 1,000 feet.
(This page contained a map depicting developed and undeveloped Gulf of Mexico
properties.)
14
<PAGE> 17
The developed and undeveloped acreage (including both leases and
concessions) that Samedan held as of December 31, 1998, is as follows:
<TABLE>
<CAPTION>
Developed Acreage (1)(2) Undeveloped Acreage (2)(3)
------------------------------ -----------------------------
Location Gross Acres Net Acres Gross Acres Net Acres
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
United States Onshore
Alabama 2,610 1,258 2,396 506
California 7,151 2,707 12,588 5,619
Colorado 67,825 63,614 41,098 32,405
Kansas 93,388 53,696 20,043 11,963
Louisiana 32,277 14,718 8,465 3,862
Mississippi 12,738 7,705 2,625 469
Montana 190,881 128,217 91,541 48,185
New Mexico 5,715 3,054 26,508 8,668
North Dakota 26,129 11,860 32,542 20,538
Oklahoma 167,550 68,156 64,411 24,908
Texas 129,838 58,503 147,337 52,562
Wyoming 34,557 15,690 47,416 21,313
Other 5,360 2,541 5,389 1,659
- -------------------------------------------------------------------------------------------------------------------
Total United States Onshore 776,019 431,719 502,359 232,657
- -------------------------------------------------------------------------------------------------------------------
United States Offshore (Federal Waters)
Alabama 11,520 4,608 161,280 67,680
California 33,074 5,727 63,884 6,283
Louisiana 716,097 313,452 480,739 245,816
Mississippi 28,171 22,621 45,056 22,975
Texas 270,581 105,538 233,538 139,895
- -------------------------------------------------------------------------------------------------------------------
Total United States Offshore (Federal Waters) 1,059,443 451,946 984,497 482,649
- -------------------------------------------------------------------------------------------------------------------
International
Argentina 28,988 3,778 85,760 11,177
Australia 926,625 368,333
China 307,398 204,438
Denmark 80,900 64,720
Ecuador 864,126 864,126
Equatorial Guinea 26,651 9,272 285,307 99,263
Ireland 296,797 169,174
Israel 885,625 354,250
Portugal 234,974 105,738
United Kingdom 130,876 8,460 396,885 131,696
Other 777,277 32,063
- -------------------------------------------------------------------------------------------------------------------
Total International 186,515 21,510 5,141,674 2,404,978
- -------------------------------------------------------------------------------------------------------------------
Total 2,021,977 905,175 6,628,530 3,120,284
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
(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 leased 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 leased 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.
15
<PAGE> 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 1998.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of March 15,
1999, with respect to the executive officers of the Registrant.
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Robert Kelley (1) 53 Chairman of the Board, President, Chief Executive Officer, Director
George L. DeMare Jr. (2) 53 Senior Vice President and Operating Committee Member of Samedan
William D. Dickson (3) 50 Senior Vice President-Finance and Treasurer of the Registrant and
Operating Committee Member of Samedan
Dan O. Dinges (4) 45 Senior Vice President and Operating Committee Member of Samedan
W. A. Poillion (5) 49 Senior Vice President and Operating Committee Member of Samedan
Orville Walraven (6) 54 Corporate Secretary of the Registrant and Senior Vice President and
Operating Committee Member of Samedan
James C. Woodson (7) 56 Senior Vice President and Operating Committee Member of Samedan
</TABLE>
- --------------
(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 General Manager of Samedan on January 1, 1998. Prior thereto,
he had served as Vice President and Onshore Division General 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 had 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 had 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 had served as
Vice President-Production and Drilling of Samedan since November 1990.
He has been 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
<PAGE> 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 had served as Vice
President-Land of Samedan since January 1, 1989. He has been 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 had 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.
16
<PAGE> 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.
<TABLE>
<CAPTION>
Dividends
High Low Per Share
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
1998
First quarter $46 3/16 $32 3/4 $.04
Second quarter $44 3/4 $35 5/16 $.04
Third quarter $38 1/4 $22 5/8 $.04
Fourth quarter $35 7/16 $21 15/16 $.04
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
</TABLE>
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, 1998, the number of holders
of record of Common Stock was 1,404. The following chart indicates the common
stockholders by category.
<TABLE>
<CAPTION>
Shares
December 31, 1998 Outstanding
- ----------------------------------------------------------------------------
<S> <C>
Individuals 459,313
Joint accounts 77,522
Fiduciaries 175,417
Institutions 2,540,037
Nominees 53,728,719
Foreign 0
- ----------------------------------------------------------------------------
Total 56,981,008
- ----------------------------------------------------------------------------
</TABLE>
18
<PAGE> 21
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts and ratios) 1998 1997 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
REVENUES AND INCOME
Revenues $ 911,616 $ 1,116,623 $ 887,203 $ 487,018 $ 358,389
Net cash provided by operating activities 324,275 445,571 380,945 238,920 188,621
Net income (164,025) 99,278 83,880 4,086 3,166
PER SHARE DATA
Basic earnings per share $ (2.88) $ 1.75 $ 1.63 $ .08 $ .06
Cash dividends $ .16 $ .16 $ .16 $ .16 $ .16
Year end stock price $ 24.63 $ 35.25 $ 47.88 $ 29.88 $ 24.75
Basic weighted average shares outstanding 56,955 56,872 51,414 50,046 49,970
FINANCIAL POSITION (at year end)
Property, plant and equipment, net:
Oil and gas mineral interests,
equipment and facilities $ 1,429,667 $ 1,546,426 $ 1,559,691 $ 831,827 $ 804,009
Total assets 1,686,080 1,852,782 1,956,938 989,176 933,516
Long-term obligations:
Long-term debt, net of current portion 745,143 644,967 798,028 376,992 376,956
Deferred income taxes 106,823 144,083 108,434 69,445 61,802
Other 52,868 56,425 50,603 33,650 19,455
Shareholders' equity 642,080 812,989 720,067 411,911 412,066
Ratio of debt to book capital .54 .44 .54 .48 .48
CAPITAL EXPENDITURES
Oil and gas mineral interests,
equipment and facilities $ 237,425 $ 320,561 $ 982,499 $ 252,977 $ 158,973
Other 2,733 8,499 3,485 6,265 2,371
- -----------------------------------------------------------------------------------------------------------------------------
Total capital expenditures $ 240,158 $ 329,060 $ 985,984 $ 259,242 $ 161,344
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>
For additional information, see "Item 8. Financial Statements and Supplementary
Data" of this Form 10-K.
<TABLE>
<CAPTION>
OPERATING STATISTICS Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
GAS
Sales (in millions) $ 441.8 $ 499.4 $ 365.4 $ 167.4 $ 174.5
Production (MMCF per day) 566.6 565.4 469.4 272.2 247.6
Average price (per MCF) $ 2.18 $ 2.48 $ 2.17 $ 1.72 $ 1.97
OIL
Sales (in millions) $ 154.3 $ 243.6 $ 225.2 $ 153.5 $ 122.9
Production (BBLS per day) 37,217 38,345 34,520 25,617 22,751
Average price (per BBL) $ 11.66 $ 17.86 $ 18.28 $ 16.78 $ 14.90
Royalty sales (in millions) $ 13.1 $ 18.1 $ 13.9 $ 7.2 $ 8.8
</TABLE>
19
<PAGE> 22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
The Company's net cash provided from operations decreased in 1998 as a
result of significantly lower commodity prices for crude oil and natural gas
and slightly lower average daily oil production. As shown below, the oil price
received by the Company has declined in each of the last three years and the
gas price received by the Company declined in 1998.
<TABLE>
<CAPTION>
CASH PROVIDED
FROM OPERATIONS AVERAGE OIL PRICES AVERAGE GAS PRICES
(millions of dollars) (Per BBL) (Per MCF)
1996 1997 1998 1996 1997 1998 1996 1997 1998
---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
$380.9 $445.6 $324.3 $18.28 $17.86 $11.66 $2.18 $2.48 $2.18
</TABLE>
The Company's unconsolidated subsidiary, Atlantic Methanol Production
Company ("AMPCO"), a 45 percent owned joint venture, is constructing a methanol
plant in Equatorial Guinea. The Company pays 50 percent of the cost of
construction for a 45 percent ownership interest. The plant construction
started during 1998 and is scheduled to be completed during the first quarter
of 2001. The construction cost of the turnkey contract is $313.5 million. Other
associated expenditures required to complete the project and produce marketable
supplies of methanol, which would include financing costs and contingencies,
are projected to be $110.3 million. The total cost of the methanol project is
estimated to be $423.8 million, with the Company responsible for $211.9
million. Payments are due upon the completion of specific phases of the
construction. During 1998, the Company paid $22.6 million toward the project
including $21.2 million in construction contract payments. The Company has
construction contract phase payments totaling $85.4 million due in 1999.
During 1998, $516.5 million was spent on exploration and development
projects and $22.6 million on the methanol project, for total capital
expenditures of $539.1 million. See chart below.
(This page contained four graphs:
1. Cash Provided from Operations (millions of dollars)
1996 - $380.9, 1997 - $445.6, 1998 - $324.3
2. Average Oil Prices (Per BBL)
1996 $18.28, 1997 - $17.86, 1998 - $11.66
3. Average Gas Prices (Per MCF)
1996 - $2.18, 1997 - $2.48, 1998 $2.18
4. 1998 Exploration, Development and Methanol Plant Expenditures
Offshore - 72.0%, Int'l - 10.0%, Onshore - 14.0%, Methanol
Plant - 4.0%, total expenditures $539.1 million)
20
<PAGE> 23
The Company's current ratio (current assets divided by current
liabilities) was 1.35:1 at December 31, 1998, compared with 1.21:1 at December
31, 1997.
The Company utilized its beginning cash, cash from operations and $100
million of borrowings under its credit facility to fund its exploration and
development expenditures, the first phase of the methanol plant construction,
and acquisition of producing properties from New England Energy, Inc. ("NEEI").
The Company used $50 million of borrowings under its credit facility to acquire
all of NEEI's producing properties and the remaining $50 million for a down
payment on the methanol plant contract and for 1998 drilling expenditures. The
NEEI acquisition added 1.0 million BBLS of oil and 50.2 BCF of gas to the
Company's reserves. The Company's cash and short-term cash investments
decreased from $55.1 million at December 31, 1997 to $19.1 million at December
31, 1998.
FINANCING
The Company's total long-term debt, net of unamortized discount, at
December 31, 1998 was $745 million compared to $645 million at December 31,
1997. The ratio of debt to book capital (defined as the Company's debt plus its
equity) was 54 percent at December 31, 1998, compared with 44 percent at
December 31, 1997.
The Company's long-term debt is comprised of: $300 million outstanding
under the Company's $300 million revolving credit facility with a group of
banks with a final maturity of December 24, 2002, $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 during
the next five years is the outstanding balance of the $300 million credit
agreement on December 24, 2002.
The Company is currently negotiating a $100 million 364 day credit
facility with a different group of banks for additional working capital with
terms and covenants similar to its existing $300 million credit facility. The
Company is also reviewing potential project-financing terms to ascertain the
feasibility of financing the methanol plant. The proceeds would enable the
Company to use cash flow to reduce long-term debt.
The Company's 1999 capital expenditures budget, which includes
payments for the methanol plant construction project, has been developed to
remain within the anticipated cash flow generated from operations under current
commodity prices.
OTHER
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.
The Company has sold a number of non-strategic oil and gas properties
over the past three years. Total amounts of oil and gas reserves associated
with these dispositions were 6.6 million BBLS of oil and 85.6 BCF of gas. In
1997, the Company sold all of 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 strategic properties.
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This statement is effective for
all fiscal years beginning after June 15, 1999. The Company will adopt SFAS No.
133 in 1999. The Company estimates there will be no material financial impact
as a result of adopting SFAS No. 133.
UNCONSOLIDATED SUBSIDIARY
The Company has one unconsolidated subsidiary, AMPCO. The net assets
of the unconsolidated subsidiary were $25.1 million at December 31, 1998.
21
<PAGE> 24
RESULTS OF OPERATIONS
The Company's consolidated financial statements for the years ended
December 31, 1998 and 1997 include a full year of Energy Development
Corporation ("EDC") operations as a wholly owned subsidiary of Samedan. The
consolidated financial statements for the year ended December 31, 1996 include
five months of EDC's operations. EDC was acquired by the Company on July 31,
1996.
NET INCOME AND REVENUES
The net loss for 1998 of $164 million included a write down of $143
million after-tax, because of downward reserve revisions, in compliance with
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of." The impact of the 35 percent decline in
the average oil prices to $11.66 per BBL was approximately $84 million in
reduced oil revenues compared to 1997. The impact of the 12 percent decline in
the average natural gas price to $2.18 per MCF was approximately $62 million in
reduced gas revenues compared to 1997.
NATURAL GAS INFORMATION
Natural gas revenues declined in 1998, despite a slight increase in
the Company's average daily production volume. Revenues were down because
natural gas prices were lower than last year primarily as a result of excess
gas in storage due to mild winter weather in the major consuming regions of the
United States. Natural gas accounted for 74 percent of the Company's total gas
and oil revenues in 1998. Gas sales and average daily production for 1997
increased 37 percent and 20 percent, respectively from 1996. The average gas
price in 1997 increased 14 percent from 1996.
(This page contained four graphs:
1. Net Income (Loss) (millions of dollars)
1996 - $83.9, 1997 - $99.3, 1998 - $(164.0) SFAS No. 121
$(143.0)
2. Natural Gas Revenues (millions of dollars)
1996 $365.4, 1997 - $499.4, 1998 - $441.8
3. Crude Oil Revenues
1996 - $225.2, 1997 - $243.6, 1998 $154.3
4. Average Daily Gas Production
1996 - Onshore - 10.6%, Offshore - 85.1%, Int'l 4.3%, total
production - 469.4 MMCF
1997 - Onshore - 28.0%, Offshore - 68.3%, Int'l 3.7%, total
production - 565.4 MMCF
1998 - Onshore - 24.6%, Offshore - 71.4%, Int'l 4.0%, total
production - 566.6 MMCF)
22
<PAGE> 25
CRUDE OIL INFORMATION
Crude oil revenues were severely impacted by the 35 percent decline in
the average price received for the Company's 1998 oil production. The Company's
average daily volumes of oil production were down slightly in 1998. The
worldwide oversupply of crude oil and reduced demand from certain Asian
countries continues to apply downward pressure on crude oil pricing. Crude oil
accounted for 26 percent of the Company's total oil and gas revenues in 1998.
Oil sales and average daily production for 1997 increased eight percent and 11
percent, respectively from 1996. The average oil price in 1997 decreased two
percent from 1996.
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 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 financial 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 1998, the Company had no oil or gas hedging transactions for
its production.
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 for its production.
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 for its production.
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 range of $1.60 to $3.59 per MMBTU. During 1996,
the Company had crude oil hedging contracts that ranged from 48 percent to 100
percent of its average daily production. Crude oil hedges were in the range of
$16.50 to $24.27 per BBL. The net effect of these 1996 hedges was a $.33 per
MCF reduction in the average natural gas price and a $2.35 per BBL decrease in
the average crude oil price realized by the Company.
(This page contained one graph:
1. Average Daily Oil Production
1996 - Onshore - 33.0%, Offshore 52.1%, Int'l 14.9%, total
production - 34,520 BBLS
1997 - Onshore - 33.7%, Offshore 44.9%, Int'l 21.4%, total
production - 38,345 BBLS
1998 - Onshore - 33.6%, Offshore 47.2%, Int'l 19.2%, total
production - 37,217 BBLS)
23
<PAGE> 26
In addition to the hedging arrangements pertaining to the Company's
production as described above, Noble Gas Marketing, Inc. ("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 1998, NGM had hedging transactions with broker-dealers that ranged from
508,811 MMBTU's to 1,061,536 MMBTU's of gas per day. At December 31, 1998, NGM
had in place hedges ranging from approximately 25,000 MMBTU's to 832,174
MMBTU's of gas per day for January 1999 to October 2000 for future physical
transactions.
In 1997, NGM had hedging transactions with broker-dealers that ranged
from 317,693 MMBTU's to 768,599 MMBTU's of gas per day. During 1996, NGM had
hedging transactions with large financial institutions that ranged from 7,475
MMBTU's to 551,126 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
Oil and gas operations expense, consisting of lease operating expense,
production taxes and other related lifting costs decreased seven percent in
1998. The chart below depicts total operating expenses and operating expenses
per MCFe, converting oil to gas on a 1:6 basis for the last three years.
Oil and gas exploration expense consists of dry hole expense,
undeveloped lease amortization, abandoned assets, seismic and other
miscellaneous exploration expense. The chart below depicts the exploration
expense for the last three years.
<TABLE>
<CAPTION>
(In thousands) 1996 1997 1998
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Dry hole expense $ 32,762 $ 46,902 $ 57,736
Undeveloped lease amortization $ 5,827 $ 8,146 $ 7,953
Abandoned assets $ 545 $ 4,923 $ 15,325
Seismic $ 11,885 $ 19,095 $ 15,754
Other $ (1,158) $ 7,632 $ 13,390
</TABLE>
(This page contained one graph:
1. Operating Expenses
Operating Expenses (millions of dollars) 1996 - $126.1, 1997 -
$160.8, 1998 - $149.0
Operating Expenses per MCFe 1996 - $.51, 1997 - $.55, 1998 -
$.52)
24
<PAGE> 27
In 1998, depreciation, depletion and amortization ("DD&A") expense
increased four percent, despite nearly flat production compared to last year.
This increase was the result of recording additional development costs and
downward reserve revisions related to certain producing properties. The chart
below depicts total DD&A expense and DD&A expense per MCFe, converting oil to
gas on a 1:6 basis for the last three years.
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's accumulated provision for future dismantlement and restoration cost
was $68.8 million at December 31, 1998 and $59.5 million at December 31, 1997.
Total estimated future dismantlement and restoration costs of $106.2 million
are included in future production and development costs for purposes of
estimating the future net revenues relating to the Company's proved reserves.
IMPAIRMENT OF OPERATING ASSETS
In the fourth quarter of 1998, the Company recorded a $223.3 million
pre-tax charge for the write-down of properties due to downward reserve
revisions. The write-down was taken under SFAS No. 121. 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 "Impairment of Operating Assets" expense.
(This page contained one graph:
1. DD&A Expense
Operating Expenses (millions of dollars) 1996 - $234, 1997 -
$300, 1998 - $313
Operating Expenses per MCFe 1996 - $.94, 1997 - $1.03, 1998 -
$1.09)
25
<PAGE> 28
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES ("SG&A")
The chart below illustrates the trend of lower SG&A costs for the last
three years. In 1996, the Company incurred $11.1 million in administrative
costs related to the acquisition of EDC and the hiring of personnel to oversee
increased operations. The Company estimates that 32 percent of the $11.1
million was due to non-recurring costs and that the decreases in SG&A costs for
1997 and 1998 are attributable primarily to the incurrence of such
non-recurring costs in 1996.
(This page contained one graph:
1. Selling, General & Administrative Expenses
SG&A Expense (millions of dollars) 1996 - $51.60, 1997 -
$50.50, 1998 - $48.10 SG&A Expense per MCFe 1996 - $.21, 1997 -
$.17, 1998 - $.17)
26
<PAGE> 29
GATHERING, MARKETING AND PROCESSING
NGM markets the majority of 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. Noble Trading, Inc. ("NTI") markets a portion of the Company's oil,
as well as certain third-party oil. The Company records all of NGM's and NTI's
sales and expenses as gathering, marketing and processing revenues and
expenses. All intercompany sales and expenses have been eliminated in the
Company's consolidated financial statements.
The gathering, marketing and processing revenues less expenses for
both NGM and NTI are reflected in the following chart. The margins for NGM on a
per MMBTU basis were $.049 for 1998, $.031 for 1997 and $.022 for 1996. The
decrease in margin on a unit rate basis for each of the years is due primarily
to increased transportation expenses and the effect of mild winter weather on
gas prices.
(This page contained one graph:
1. Gathering, Marketing & Processing Gross Margin (millions of
dollars) NGM 1996 - $12.8, 1997 - $9.6, 1998 - $7.0 NTI 1996 -
$7.4, 1997 - $6.5, 1998 - $6.6)
27
<PAGE> 30
FUTURE TRENDS
The uncertainty of oil and gas prices continues to impact the domestic
oil and gas industry. The Company cannot predict the extent to which its
operations will be impacted by inflation, government regulation or changing
commodity prices. However, the Company expects low oil and gas prices to
continue in the short term. Therefore, it has curtailed its exploration and
development expenditure budget 61 percent for 1999, excluding the methanol
plant. During 1998, $516.5 million was spent on exploration and development
projects and $22.6 million on the methanol project, for a total expenditure of
$539.1 million. The 1999 exploration and development budget has been set at a
total of $305.9 million, exclusive of producing property acquisitions, of which
$201.3 million is budgeted for oil and gas exploration and development projects
and $104.6 million is budgeted for the methanol plant and related facilities.
The Company expects to fund its 1999 exploration and development expenditures
from cash flow from operations.
[1999 EXPLORATION, DEVELOPMENT AND
METHANOL PLANT BUDGET CHART]
$305.9 million
METHANOL PLANT TURNKEY
CONSTRUCTION CONTRACT PAYMENTS
(millions of dollars)
<TABLE>
<CAPTION>
1998 1999 2000 2001
<S> <C> <C> <C>
$21.2 $85.4 $45.5 $4.7
</TABLE>
Management believes that reduced exploration and development
expenditures industrywide, because of low commodity prices, will have the
effect of reducing supplies in the future, thereby supporting prices. The
Company expects its production volumes for 1999 to decrease as funds are
diverted to other economical projects such as the methanol plant.
The Year 2000 issue is the result of computer programs being written
using two digits rather than four to define the applicable year. Computer
equipment and software and devices with embedded technology that are
time-sensitive may recognize a date using "00" as the year 1900 rather than the
year 2000. This could result in a system failure or miscalculations causing
disruptions of operations, including, among other things, a temporary inability
to process transactions, send invoices, or engage in similar normal business
activities.
The Company has undertaken various initiatives intended to ensure that
its computer equipment and software will function properly with respect to
dates in the year 2000 and thereafter. For this purpose, the term "computer
equipment and software" includes systems that are commonly thought of as
information technology ("IT") systems, including accounting, data processing,
and telephone/PBX systems, and other miscellaneous systems, as well as systems
that are not commonly thought of as IT systems, such as field operations
equipment, alarm systems, sprinkler systems, fax machines, or other
miscellaneous systems. Both IT and non-IT systems may contain imbedded
technology, which complicates the Company's Year 2000 identification,
assessment, remediation, and testing efforts. In addition, in the ordinary
course of replacing computer equipment and software, the Company attempts to
obtain replacements that it believes are Year 2000 compliant. Utilizing
internal resources to identify and assess needed Year 2000 remediation, the
Company currently anticipates that its Year 2000 identification, assessment,
remediation, and testing efforts, which began in January 1998, will be
completed by September 30, 1999, and that such efforts will be completed prior
to any currently anticipated impact on its computer equipment and software. The
Company estimates that as of December 31, 1998, it had completed approximately
65% of the initiatives that it believes will be necessary
(This page contained two graphs:
1. Methanol Plant Turnkey Construction Contract Payments (millions
of dollars) 1998 - $21.2, 1999 - $85.4, 2000 - $45.5, 2001 -
$4.7
2. 1999 Exploration, Development and Methanol Plant Budget
Offshore - 30.0%, Int'l - 20.0%, Onshore - 16.0%, Methanol
Plant - 34.0%, total expenditures $305.9 million)
28
<PAGE> 31
to fully address potential Year 2000 issues relating to its computer equipment
and software. The projects comprising the remaining 35% of the initiatives are
in process and expected to be completed by September 30, 1999.
<TABLE>
<CAPTION>
Percent
Year 2000 Initiative Time Frame Complete
- --------------------------------------------------------------------------------------------
<S> <C> <C>
Identification and assessment of IT systems March 31, 1999 90%
(Company and subsidiaries)
Identification and assessment of critical non-IT systems June 30, 1999 25%
(Company and subsidiaries)
Remediation and testing of IT and non-IT systems of December 31, 1998 100%
subsidiaries other than Samedan and subsidiaries
Remediation and testing of IT and non-IT systems of March 31, 1999 90%
Samedan and subsidiaries
Remediation and testing of Company's central IT March 31, 1999 90%
and non-IT systems
Replacement and testing of third party software June 30, 1999 75%
Identification and assessment of field equipment used in
oil and gas producing operations June 30, 1999 10%
Remediation and testing of field equipment September 30, 1999 0%
</TABLE>
The Company plans to mail letters in early March 1999 to its
significant vendors and service providers and has verbally communicated with
many strategic customers to determine the extent to which interfaces with such
entities are vulnerable to Year 2000 issues and whether the products and
services purchased from or by such entities are Year 2000 compliant.
The Company is funding its Year 2000 efforts primarily with internal
resources and does not anticipate making any expenditures in connection
therewith except for the purchase of third party software that it otherwise
would not have purchased or would have purchased at a later date. Although the
Company does not separately track its internal costs related to Year 2000
efforts, which include compensation of employees working on Year 2000 projects,
it believes that such costs will not exceed $75,000, of which approximately
$65,000 had been incurred as of December 31, 1998. The Company estimates that
these internal and external costs will represent less than five percent of
total IT-related costs for 1998 and 1999 and that none of the Company's IT
initiatives that are not related to the Year 2000 issue will be materially
delayed or impacted by Year 2000 efforts.
The Company presently believes that the Year 2000 issue will not pose
significant operational problems for the Company. However, if all Year 2000
issues are not properly identified, or assessment, remediation, and testing are
not effected timely, there can be no assurance that the Year 2000 issue will
not materially adversely impact the Company's results of operations or
adversely affect the Company's relationships with customers, vendors, or
others. Additionally, there can be no assurance that the Year 2000 issues of
other entities will not have a material adverse impact on the Company's systems
or results of operations.
The costs of the Company's Year 2000 identification, assessment,
remediation, and testing efforts and the dates on which the Company believes it
will complete such efforts are based upon management's estimates, which were
derived using numerous assumptions regarding future events, including the
continued availability of certain resources, third-party remediation plans and
other factors. There can be no assurance that these estimates will prove to be
accurate, and actual results could differ materially from those currently
anticipated. Specific factors that could cause such material differences
include, but are not limited to, the availability and cost of personnel trained
in Year 2000 issues, the ability to identify, assess, remediate, and test all
relevant computer codes and imbedded technology, and similar uncertainties. In
addition, variability of definitions of "compliance with Year 2000" may lead to
claims on the Company, the impact of which is not currently estimable. No
assurance can be given that the aggregate cost of defending and resolving such
claims, if any, will not materially adversely affect the Company's results of
operations.
29
<PAGE> 32
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to market risk in the normal course of its
business operations. Management believes that the Company is well positioned
with its mix of oil and gas reserves 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 derivative hedging
and may do so in the future as a means of controlling its exposure to price
changes. During 1998, the Company had no oil or gas hedging transactions for
its production. NGM, from time to time, employs hedging arrangements in
connection with its purchases and sales of production. While most of NGM's
purchases are made for an index-based price, NGM's customers often require
prices that are either fixed or related to NYMEX. In order to establish a fixed
margin and mitigate the risk of price volatility, NGM may convert a fixed or
NYMEX sale to an index-based sales price (such as by purchasing an index-based
futures contract obligating NGM for delivery of production). Due to the size of
such transactions and certain restraints imposed by contract and by Company
guidelines, as of December 31, 1998 the Company had no material market risk
exposure from NGM's hedging activity.
The Company has a $300 million credit agreement (see Note 3 - Debt, to
the Consolidated Financial Statements) which exposes the Company to the risk of
earnings or cash flow loss due to changes in market interest rates. At December
31, 1998, there was $300 million outstanding under the credit facility with a
maturity date of December 24, 2002. The interest rate charged, which is based
upon a Eurodollar rate plus 22.5 basis points, was 5.3 percent at December 31,
1998. All other Company long-term debt is fixed-rate and, therefore, does not
expose the Company to the risk of earnings or cash flow loss due to changes in
market interest rates.
The Company does not invest in foreign currency derivatives. The U.S.
dollar is considered the primary currency for each of the Company's
international operations. Transactions that are completed in a foreign currency
are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented
and the Company does not believe it is currently exposed to any material risk
of loss on this basis. Such gains or losses are included in other expense on
the income statement. However, certain sales transactions are concluded in
foreign currencies and the Company therefore is exposed to potential risk of
loss based on fluctuation in exchange rates from time to time.
30
<PAGE> 33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants................................ 32
Consolidated Balance Sheet as of December 31, 1998 and 1997............. 33
Consolidated Statement of Operations for each of the three years in the
period ended December 31, 1998........................................ 34
Consolidated Statement of Cash Flows for each of the three years in the
period ended December 31, 1998........................................ 35
Consolidated Statement of Shareholders' Equity for each of the three
years in the period ended December 31, 1998........................... 36
Notes to Consolidated Financial Statements.............................. 37
Supplemental Oil and Gas Information (Unaudited)........................ 49
Interim Financial Information (Unaudited)............................... 55
</TABLE>
All financial statement schedules have been omitted because the
required information is not present or is not present in amounts sufficient to
require submission of the schedule or because the information required is
included in the financial statements, including the notes thereto.
31
<PAGE> 34
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,
1998 and 1997, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
January 29, 1999
32
<PAGE> 35
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES
December 31,
- -------------------------------------------------------------------------------------------------------------------
(In thousands, except share amounts) 1998 1997
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and short-term cash investments $ 19,100 $ 55,075
Accounts receivable - trade 106,513 162,667
Materials and supplies inventories 3,006 2,805
Other current assets 59,670 15,385
- -------------------------------------------------------------------------------------------------------------------
Total current assets 188,289 235,932
- -------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 2,873,076 2,766,741
Other 42,841 40,286
- -------------------------------------------------------------------------------------------------------------------
2,915,917 2,807,027
Accumulated depreciation, depletion and amortization (1,486,250) (1,260,601)
- -------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 1,429,667 1,546,426
- -------------------------------------------------------------------------------------------------------------------
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY 25,061
- -------------------------------------------------------------------------------------------------------------------
OTHER ASSETS 43,063 70,424
- -------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 1,686,080 $ 1,852,782
- -------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 108,538 $ 163,563
Other current liabilities 28,815 28,456
Income taxes - current 1,813 2,299
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 139,166 194,318
- -------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES 106,823 144,083
- -------------------------------------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 52,868 56,425
- -------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 745,143 644,967
- -------------------------------------------------------------------------------------------------------------------
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;
58,505,908 and 58,423,438 shares issued in 1998 and 1997, respectively 195,018 194,743
Capital in excess of par value 360,008 358,054
Retained earnings 102,472 275,610
- -------------------------------------------------------------------------------------------------------------------
657,498 828,407
Less common stock in treasury, at cost (1998 and 1997, 1,524,900 shares) (15,418) (15,418)
- -------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 642,080 812,989
- -------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND EQUITY $ 1,686,080 $ 1,852,782
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
33
<PAGE> 36
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
Year ended December 31,
- -------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts) 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales and royalties $ 609,164 $ 761,145 $ 604,588
Gathering, marketing and processing 284,407 329,868 273,690
Other income 18,045 25,610 8,925
- -------------------------------------------------------------------------------------------------------------------
Total Revenue 911,616 1,116,623 887,203
- -------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES:
Oil and gas exploration 110,158 86,698 49,861
Oil and gas operations 149,030 160,765 126,044
Gathering, marketing and processing 270,826 313,807 253,529
Depreciation, depletion and amortization 313,191 300,354 233,604
Impairment of operating assets 223,251
Selling, general and administrative 48,110 50,545 51,567
Interest 50,511 53,008 38,474
Interest capitalized (6,753) (6,239) (2,165)
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 1,158,324 958,938 750,914
- -------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE TAXES (246,708) 157,685 136,289
- -------------------------------------------------------------------------------------------------------------------
INCOME TAX PROVISION (BENEFIT):
Current (19,679) 25,569 31,376
Deferred (63,004) 32,838 21,033
- -------------------------------------------------------------------------------------------------------------------
Total Tax Provision (Benefit) (82,683) 58,407 52,409
- -------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ (164,025) $ 99,278 $ 83,880
- -------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS (LOSS) PER SHARE $ (2.88) $ 1.75 $ 1.63
- -------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS (LOSS) PER SHARE $ (2.88) $ 1.73 $ 1.55
- -------------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 56,955 56,872 51,414
Diluted 56,955 57,421 57,223
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
34
<PAGE> 37
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
Year ended December 31,
- -------------------------------------------------------------------------------------------------------------------
(In thousands) 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (164,025) $ 99,278 $ 83,880
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 313,191 300,354 233,604
Impairment of operating assets 223,251
Amortization of undeveloped leasehold costs, net 7,953 8,146 5,827
(Gain) loss on disposal of assets 15,434 (11,007) (3,335)
Noncurrent deferred income taxes (37,260) 35,650 38,989
Increase (decrease) in other deferred credits (3,558) 5,822 14,409
(Increase) decrease in other 12,709 1,684 (16,296)
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable 56,154 43,484 (89,141)
(Increase) decrease in other current assets (44,423) (25,053) 10,608
Increase (decrease) in accounts payable (55,025) (29,845) 37,536
Increase (decrease) in other current liabilities (126) 17,058 64,864
- -------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 324,275 445,571 380,945
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (431,716) (326,958) (257,719)
Investment in unconsolidated subsidiary (25,061)
Acquisition of Energy Development Corporation (768,185)
Proceeds from sale of property, plant and equipment 3,412 54,543 26,758
- -------------------------------------------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (453,365) (272,415) (999,146)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Exercise of stock options 2,228 2,744 7,851
Cash dividends paid (9,113) (9,100) (8,311)
Proceeds from bank borrowings 800,000
Repayment of bank debt (549,000) (99,000)
Proceeds from issuance of long-term debt 100,000 342,507
- -------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 93,115 (212,849) 700,540
- -------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS (35,975) (39,693) 82,339
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 55,075 94,768 12,429
- -------------------------------------------------------------------------------------------------------------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 19,100 $ 55,075 $ 94,768
- -------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 43,368 $ 46,140 $ 28,652
Income taxes $ 4,276 $ 32,415 $ 11,500
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
35
<PAGE> 38
<TABLE>
<CAPTION>
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
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
JANUARY 1, 1996 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
- ------------------------------------------------------------------------------------------------------------------
Net Loss (164,025)
Exercise of stock options 82,470 275 1,954
Cash dividends ($.16 per share) (9,113)
- ------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 58,505,908 $195,018 $360,008 $(15,418) $ 102,472
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
36
<PAGE> 39
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, 1998.
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 International
Samedan Methanol
Samedan, Mediterranean Sea, Inc.
Samedan Pipe Line Corporation
Samedan Royalty Corporation
Samedan of Tunisia, Inc.
Energy Development Corporation ("EDC")
EDC Argentina, Inc.
EDC Australia, Ltd.
EDC China, Inc.
EDC Denmark
EDC Ecuador Limited
EDC (Europe) Limited
EDC HIPS, Inc.
EDC Portugal Ltd.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, Inc.
NATURE OF OPERATIONS
The Company is an independent energy company 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 in Argentina,
China, Ecuador, Equatorial Guinea, the Mediterranean, the North Sea and the
United Kingdom. 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
37
<PAGE> 40
statements as well as amounts of revenues and expenses recognized during the
reporting period. Of the estimates and assumptions that affect reported
results, the estimate of the Company's oil and gas reserves is the most
significant.
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is considered the primary currency for each of the Company's
international operations. Transactions that are completed in a foreign currency
are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented
and are included in other expense on the income statement.
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 $68.8 million for such future costs classified with accumulated DD&A
in the December 31, 1998 balance sheet. The total estimated future
dismantlement and restoration costs of $106.2 million are included in future
production and development costs for purposes of estimating the future net
revenues relating to the Company's proved reserves. 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.
Individually significant undeveloped oil and gas properties 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.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the development
and construction of significant properties or projects.
38
<PAGE> 41
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.
BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
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. The following table summarizes the
calculation of basic earnings per share ("EPS") and diluted EPS components
required by SFAS No. 128, as of December 31:
<TABLE>
<CAPTION>
1998 1997 1996
---------------------------- --------------------------- ----------------------------
(in thousands Income Shares Income Shares Income Shares
except per share amounts) (Numerator) (Denominator) (Numerator) (Denominator) (Numerator) (Denominator)
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net income/shares $(164,025) 56,955 $99,278 56,872 $83,880 51,414
- ---------------------------------------------------------------------------------------------------------------------
BASIC EPS $(2.88) $1.75 $1.63
- ---------------------------------------------------------------------------------------------------------------------
Net income/shares $(164,025) 56,955 $99,278 56,872 $83,880 51,414
Effect of Diluted Securities
Stock options (1) 549 556
4 1/4% Convertible
Subordinated Notes (2) 4,692 5,253
-------------------------------------------------------------------------------------
Adjusted net income
and shares $(164,025) 56,955 $99,278 57,421 $88,572 57,223
- ---------------------------------------------------------------------------------------------------------------------
DILUTED EPS $(2.88) $1.73 $1.55
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) The 1998 diluted EPS is antidilutive as a result of the net
operating loss; therefore, the basic EPS and diluted EPS are the
same.
(2) The 4 1/4% Convertible Subordinated Notes were converted on
November 1, 1996.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan and EDC have gas sales contracts 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 $14.8 million and
$21.6 million for 1998 and 1997, 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 $19.1 million and
$18.5 million for 1998 and 1997, respectively, and are valued at the amount
which is expected to be received.
39
<PAGE> 42
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 1998, the Company had no oil or gas hedging transactions for
its production.
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 for its production.
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 for its production.
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 range of $1.60 to $3.59 per MMBTU. During 1996,
the Company had crude oil hedging contracts that ranged from 48 percent to 100
percent of its average daily production. Crude oil hedges were in the range of
$16.50 to $24.27 per BBL. The net effect of these 1996 hedges was a $.33 per
MCF reduction in the average natural gas price and a $2.35 per BBL decrease 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 margin and minimizing the risk of price volatility.
During 1998, NGM had hedging transactions with broker-dealers that ranged from
508,811 MMBTU's to 1,061,536 MMBTU's of gas per day. At December 31, 1998, NGM
had in place hedging transactions ranging from 25,000 MMBTU's to 832,174
MMBTU's of gas per day for January 1999 to October 2000 for future physical
transactions.
In 1997, NGM had hedging transactions with broker-dealers that ranged
from 317,693 MMBTU's to 768,599 MMBTU's of gas per day. In 1996, NGM had
hedging transactions with large financial institutions that ranged from 7,475
MMBTU's to 551,126 MMBTU's of gas per day. 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.
40
<PAGE> 43
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.
UNCONSOLIDATED SUBSIDIARY
The Company has one unconsolidated subsidiary, Atlantic Methanol
Production Company ("AMPCO"), a 45 percent owned joint venture that is
constructing a methanol plant in Equatorial Guinea. AMPCO is accounted for on
the equity method within Samedan Methanol. The plant construction started
during 1998 and is scheduled to be completed during the first quarter of 2001.
The net assets of the unconsolidated subsidiary were $25.1 million at December
31, 1998.
RECLASSIFICATION
Certain reclassifications have been made to the 1996 and 1997
consolidated financial statements to conform to the 1998 presentation.
RECENTLY ISSUED PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." This
statement is effective for all fiscal years beginning after June 15, 1999. The
Company will adopt SFAS No. 133 in 1999. The Company estimates implementation
of this statement will not have a material financial impact.
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.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on
the quoted market prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company's
financial instruments as of December 31, for each of the years are as follows:
<TABLE>
<CAPTION>
1998 1997
---------------------------- -----------------------------
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash and short-term cash investments $ 19,100 $ 19,100 $ 55,075 $ 55,075
Long-term debt (including current portion) $ 745,143 $ 760,750 $ 644,967 $ 655,400
</TABLE>
41
<PAGE> 44
NOTE 3 - DEBT
A summary of debt at December 31 follows:
<TABLE>
<CAPTION>
(in thousands) 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C>
$300 million Credit Agreement $ 300,000 $ 200,000
7 1/4% Notes Due 2023 100,000 100,000
8% Senior Notes Due 2027 250,000 250,000
7 1/4% Senior Debentures Due 2097 100,000 100,000
- ------------------------------------------------------------------------------
Outstanding debt 750,000 650,000
- ------------------------------------------------------------------------------
Less: unamortized discount 4,857 5,033
- ------------------------------------------------------------------------------
Long-term debt $ 745,143 $ 644,967
- ------------------------------------------------------------------------------
</TABLE>
Total long-term debt at December 31, 1998 was $745 million compared to
$645 million (including current portion) at December 31, 1997, an increase of
15.5 percent. The ratio of debt to book capital (defined as the Company's debt
plus its equity) was 54 percent at December 31, 1998 compared with 44 percent
at December 31, 1997.
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 5.3
percent at December 31, 1998. 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. An $800 million credit agreement was terminated on December 24,
1997, and the outstanding balance of $200 million was refinanced under the $300
million credit agreement. The weighted average interest rate on the borrowings
during 1997 was 6.9 percent. The weighted average interest rate on the
borrowings during 1998 was 6.8 percent.
Total long-term debt outstanding at December 31, 1998 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.
NOTE 4 - INCOME TAXES
The following table details the difference between the federal
statutory tax rate and the effective tax rate for the years ended December 31:
<TABLE>
<CAPTION>
(Amounts expressed in percentages) 1998 1997 1996
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory rate (benefit) (35.0) 35.0 35.0
Effect of:
Percentage depletion (.1) (.1)
State taxes (.2) .7
Foreign taxes .4 .8 3.1
Losses from international operations .9 1.4 .1
Other, net .4 (.1) (.3)
- ------------------------------------------------------------------------------------
Effective rate (33.5) 37.0 38.5
- ------------------------------------------------------------------------------------
</TABLE>
42
<PAGE> 45
The net current deferred tax asset (liability) in the following table
is classified as Other Current Assets in the Consolidated Balance Sheet. The
tax effects of temporary differences which gave rise to deferred tax assets and
liabilities as of December 31 were:
<TABLE>
<CAPTION>
(in thousands) 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
U.S. and State Current Deferred Tax Assets:
Accrued expenses $ 1,684 $ (2,269)
Deferred income 1,386 3,127
Minimum tax 17,939
Allowance for doubtful accounts 304 496
Net operating loss carryforward 6,710
Other 436 903
- -------------------------------------------------------------------------------------------------------------------
Net current deferred tax asset 28,459 2,257
- -------------------------------------------------------------------------------------------------------------------
U.S. and State Non-current Deferred Tax Liabilities:
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments (104,691) (138,771)
Accrued expenses 6,449 4,390
Deferred income 3,306 6,351
Allowance for doubtful accounts 3,930
Income tax accruals 10,465 10,688
Other 2,448 1,548
- -------------------------------------------------------------------------------------------------------------------
Net non-current deferred liability (78,093) (115,794)
- -------------------------------------------------------------------------------------------------------------------
U.S. and state net deferred tax liability (49,634) (113,537)
- -------------------------------------------------------------------------------------------------------------------
Foreign Deferred Tax Liabilities:
Property, plant and equipment of
foreign operations (28,730) (28,289)
- -------------------------------------------------------------------------------------------------------------------
Deferred tax liability (28,730) (28,289)
- -------------------------------------------------------------------------------------------------------------------
Total deferred taxes $ (78,364) $ (141,826)
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
The components of income from operations before income taxes for each
year are as follows:
<TABLE>
<CAPTION>
(in thousands) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Domestic $(225,692) $159,535 $137,462
Foreign (21,016) (1,850) (1,173)
- -------------------------------------------------------------------------------------------------------------------
$(246,708) $157,685 $136,289
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
The income tax provisions relating to operations for each year consist
of the following:
<TABLE>
<CAPTION>
(in thousands) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
U.S. current $(20,842) $22,146 $26,425
U.S. deferred (62,366) 34,344 17,918
State current 236 587 844
State deferred (1,080) (622) 644
Foreign current 927 2,836 4,107
Foreign deferred 442 (884) 2,471
- -------------------------------------------------------------------------------------------------------------------
$(82,683) $58,407 $52,409
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
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.
43
<PAGE> 46
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 adoption of the 1992 Plan, 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, by 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, 1998, the Company had reserved 3,719,923 shares of common stock for
issuance, including 1,186,028 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, 1998, the Company had reserved 424,000 shares of common stock for
issuance, including 225,500 shares available for grant, under its 1988 Plan.
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.
Stock options outstanding under the plans mentioned above and two previously
terminated plans are presented for the periods indicated.
<TABLE>
<CAPTION>
Number Option
of Shares Price Range
- --------------------------------------------------------------------------------
<S> <C> <C>
OUTSTANDING DECEMBER 31, 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
- -------------------------------------------------------------------------------
Granted 722,604 $35.94-$37.75
Exercised (82,470) $11.63-$40.38
Canceled (28,227) $24.25-$40.38
- -------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1998 2,817,242 $13.38-$40.38
- -------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 1998 1,555,976 $13.38-$40.38
- -------------------------------------------------------------------------------
</TABLE>
The SFAS No. 123 method of accounting 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 1998, 1997 and 1996,
respectively as follows:
<TABLE>
<CAPTION>
(Amounts expressed in percentages) 1998 1997 1996
- -----------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest rate 5.75 6.03 6.62
Dividend yield .40 .40 .40
Expected volatility 32.66 32.97 32.89
</TABLE>
44
<PAGE> 47
The weighted average fair value of options granted using the
Black-Scholes option pricing model for 1998, 1997 and 1996, respectively is as
follows:
<TABLE>
<CAPTION>
(amounts expressed in dollars) 1998 1997 1996
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Black-Scholes model weighted average fair value
option price $19.02 $18.28 $18.95
</TABLE>
The Company applies APB Opinion No. 25 in accounting for its fixed
price stock options. Accordingly, no compensation cost for options has been
recognized in the financial statements. The chart below sets forth the
Company's net income and earnings per share for each of the years ended
December 31, as reported and on a pro forma basis as if the compensation cost
of stock options had been determined consistent with SFAS No. 123, "Accounting
for Stock-Based Compensation."
<TABLE>
<CAPTION>
(in thousands except per share amounts) 1998 1997 1996
- ---------------------------------------------------------------------------------------------
<S> C> <C> <C>
Net Income:
As Reported $ (164,025) $ 99,278 $ 83,880
Pro Forma $ (171,741) $ 95,591 $ 82,447
Basic Earnings Per Share:
As Reported $ (2.88) $ 1.75 $ 1.63
Pro Forma $ (3.02) $ 1.68 $ 1.60
Diluted Earnings Per Share:
As Reported $ (2.88) $ 1.73 $ 1.55
Pro Forma $ (3.02) $ 1.66 $ 1.44
</TABLE>
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT PLANS
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 of
equity securities and fixed income investments.
The Company sponsors other plans for the benefit of its employees and
retirees. These plans include health care and life insurance benefits. The
following table reflects the required SFAS No. 132, "Employers' Disclosures
About Pension and Other Postretirement Benefits," disclosures at December 31:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
------------------------------ -----------------------------
(in thousands) 1998 1997 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ 62,487 $ 51,366 $2,384 $ 2,152
Service cost 3,811 3,003 268 210
Interest cost 4,704 4,078 185 154
Plan participants' contributions 22 19
Amendments 489 540
Actuarial gain (loss) 14,059 6,208 358 (85)
Benefit paid (2,727) (2,708) (30) (66)
- -------------------------------------------------------------------------------------------------------------------
Benefit obligation at year end $ 82,823 $ 62,487 $3,187 $ 2,384
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
45
<PAGE> 48
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
------------------------------ ---------------------------
(dollars in thousands) 1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 55,611 $ 47,921 $ $
Actual return on plan assets 7,322 10,059
Employer contribution 351 339 30 66
Benefit paid (2,725) (2,708) (30) (66)
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan at end of year $ 60,559 $ 55,611 $ $
- -------------------------------------------------------------------------------------------------------------------
Fund status $ (22,264) $ (6,876) $ (3,187) $ (2,384)
Unrecognized net actuarial loss (gain) 2,157 (8,199) 790 455
Unrecognized prior service cost 3,327 3,130
Unrecognized net transition obligation (assets) 1,263 1,288
- -------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit costs $ (15,517) $ (10,657) $ (2,397) $ (1,929)
- -------------------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 3,811 $ 3,003 $ 268 $ 210
Interest cost 4,704 4,078 185 154
Expected return on plan assets (3,908) (3,582)
Transition (assets)obligation recognition 24 24
Amortization of prior service cost 291 260
Recognized net actuarial loss 286 155 23 14
- -------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ 5,208 $ 3,938 $ 476 $ 378
- -------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31,
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets 8.50% 8.50% 8.50% 8.50%
Rate of compensation increase 5.50% 5.50% 5.50% 5.50%
</TABLE>
The following table reflects the aggregate pension obligation
components required by SFAS No. 132 for the defined benefit pension plan and
the restoration benefit plan, which are aggregated in the previous tables, at
December 31:
<TABLE>
<CAPTION>
Defined Benefit Restoration
Pension Plan Benefit Plan
------------------------------ ---------------------------
(in thousands) 1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
AGGREGATED PENSION BENEFITS
Aggregate fair value of plan assets $ 60,559 $ 55,611 $ $
Aggregate accumulated benefit obligation 68,283 52,134 14,540 10,353
- -------------------------------------------------------------------------------------------------------------------
Fund status of net periodic
benefit assets (obligation) $ (7,724) $ 3,477 $ (14,540) $ (10,353)
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
Assumed health care cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
1-Percentage- 1-Percentage-
(in thousands) Point increase Point decrease
- --------------------------------------------------------------------------------------------------
<S> <C> <C>
Effect on total service and interest cost components $ 519 $ 397
Effect on postretirement benefit obligation $ 2,930 $2,312
</TABLE>
46
<PAGE> 49
EMPLOYEE SAVINGS PLAN ("ESP")
The Company has an 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. The following table indicates the Company's contribution at
December 31:
<TABLE>
<CAPTION>
(in thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Employers' plan contribution $1,938 $1,369 $1,053
</TABLE>
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 pro forma information for the Company has been prepared
assuming the acquisition had taken place at the beginning of 1996:
<TABLE>
<CAPTION>
Pro Forma
(unaudited)
(in thousands) 1996
- -----------------------------------------------------------------------------
<S> <C>
Revenues $ 1,103,334
Net income $ 74,082
Basic earnings per share $ 1.44
Diluted earnings per share $ 1.29
</TABLE>
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.
NOTE 8 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Included in accounts receivable-trade is an allowance for doubtful
accounts at December 31:
<TABLE>
<CAPTION>
(in thousands) 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C>
Allowance for doubtful accounts $1,146 $ 1,401
</TABLE>
Other current assets include the following at December 31:
<TABLE>
<CAPTION>
(in thousands) 1998 1997
- -------------------------------------------------------------------------------
<S> <C> <C>
Deferred tax asset $ 28,459 $ 2,257
Other current liabilities include the following at December 31:
</TABLE>
<TABLE>
<CAPTION>
(in thousands) 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C>
Gas imbalance liabilities $4,761 $ 4,153
</TABLE>
47
<PAGE> 50
Oil and gas operations expense included the following for the years
ended December 31:
<TABLE>
<CAPTION>
(in thousands) 1998 1997 1996
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Lease operating expense $ 142,673 $ 151,712 $ 116,692
Production taxes $ 8,436 $ 11,947 $ 10,108
</TABLE>
Oil and gas exploration expense included the following for the years
ended December 31:
<TABLE>
<CAPTION>
(in thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Dry hole expense $ 57,736 $ 46,902 $ 32,762
Undeveloped lease amortization $ 7,953 $ 8,146 $ 5,827
Abandoned assets $ 15,325 $ 4,923 $ 545
Seismic $ 15,754 $ 19,095 $ 11,885
</TABLE>
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
The Company adopted SFAS No. 121, "Accounting for Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of," during 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 is charged to "Impairment of Operating Assets." The Company recorded
no asset impairments under SFAS No. 121 during 1997 and 1996.
In December 1998, the Company recognized a pre-tax charge of $223.3
million for impairment of various properties acquired from Energy Development
Corporation in 1996 and for the performance of certain other oil and gas
properties. The primary triggering event was downward reserve revisions of
approximately 5.9 million BBLS of oil and 155.9 BCF of gas recorded in the
fourth quarter of 1998.
48
<PAGE> 51
SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
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.
PROVED GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve
engineers and sets forth the changes in estimated quantities of proved gas
reserves of the Company during each of the three years presented.
<TABLE>
<CAPTION>
Natural Gas and Casinghead Gas (MMCF)
- ------------------------------------------------------------------------------------------------------------------------
Other Equatorial United
PROVED RESERVES AS OF: United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1998 1,107,158 322,205 5,565 47,287 1,482,215
Revisions of previous estimates (155,314) 396 27 (1,030) (155,921)
Extensions, discoveries and
other additions 71,061 71,061
Production (196,220) (959) (206) (7,201) (204,586)
Sale of minerals in place (2,232) (2,232)
Purchase of minerals in place 48,769 48,769
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 873,222 321,642 5,386 39,056 1,239,306
- -----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
- -----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1997 1,079,607 26,601 5,676 44,366 1,156,250
Revisions of previous estimates (1,228) (2,554) 545 (5) 904 (2,338)
Extensions, discoveries and
other additions 226,546 322,205 7,025 555,776
Production (195,085) (1,892) (545) (106) (5,008) (202,636)
Sale of minerals in place (6,934) (22,299) (29,233)
Purchase of minerals in place 4,252 144 4,396
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997 1,107,158 322,205 5,565 47,287 1,482,215
- -----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
- -----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1996 818,301 32,038 850,339
Revisions of previous estimates (30,618) 676 (8) (3,460) (33,410)
Extensions, discoveries and
other additions 127,399 600 9,225 137,224
Production (162,996) (3,435) (50) (1,619) (168,100)
Sale of minerals in place (49,851) (4,286) (54,137)
Purchase of minerals in place 377,372 1,008 5,734 40,220 424,334
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1996 1,079,607 26,601 5,676 44,366 1,156,250
- -----------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED GAS RESERVES AS OF:
- -----------------------------------
January 1, 1999 818,787 12,862 5,386 39,058 876,093
January 1, 1998 1,022,192 13,425 5,565 47,289 1,088,471
January 1, 1997 1,010,837 26,601 5,676 17,981 1,061,095
January 1, 1996 750,753 32,036 782,789
</TABLE>
- --------------
49
<PAGE> 52
PROVED OIL RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve
engineers and sets forth the changes in estimated quantities of proved oil
reserves of the Company during each of the three years presented.
<TABLE>
<CAPTION>
Crude Oil and Condensate (BBLS in thousands)
- -------------------------------------------------------------------------------------------------------------------------
Other Equatorial United
PROVED RESERVES AS OF: United States Int'l Guinea Argentina Kingdom TOTAL
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1998 89,065 22,766 11,997 7,035 130,863
Revisions of previous estimates (5,935) 166 16 (129) (5,882)
Extensions, discoveries and
other additions 4,802 35 4,837
Production (11,540) (931) (885) (795) (14,151)
Sale of minerals in place (155) (155)
Purchase of minerals in place 1,069 1,069
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 77,306 22,001 11,128 6,146 116,581
- -----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
- -----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1997 82,317 3,435 8,276 13,007 8,712 115,747
Revisions of previous estimates 1,516 1,676 117 (133) (795) 2,381
Extensions, discoveries and
other additions 16,501 (1) 15,212 31,712
Production (11,450) (426) (839) (877) (882) (14,474)
Sale of minerals in place (184) (4,797) (4,981)
Purchase of minerals in place 365 113 478
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997 89,065 22,766 11,997 7,035 130,863
- -----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
- -----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1996 70,907 4,090 9,011 84,008
Revisions of previous estimates (187) 218 57 36 420 544
Extensions, discoveries and
other additions 7,701 51 2,456 10,208
Production (10,785) (708) (792) (382) (405) (13,072)
Sale of minerals in place (1,239) (216) (1,455)
Purchase of minerals in place 15,920 13,353 6,241 35,514
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1996 82,317 3,435 8,276 13,007 8,712 115,747
- -----------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED OIL RESERVES AS OF:
- -----------------------------------
January 1, 1999 72,949 11,425 11,128 4,346 99,848
January 1, 1998 82,713 12,191 11,997 5,234 112,135
January 1, 1997 78,564 3,322 6,956 13,007 6,049 107,898
January 1, 1996 67,368 3,976 7,691 79,035
</TABLE>
- -------------
Proved Reserves. Proved reserves are estimated quantities of crude
oil, natural gas, natural gas liquids and condensate liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.
Proved Developed Reserves. Proved developed reserves are proved
reserves which are expected to be recovered through existing wells with
existing equipment and operating methods.
50
<PAGE> 53
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.
Amounts are presented in accordance with SFAS No. 19, and may not agree with
amounts determined using traditional industry definitions.
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------------------------------------------------------------------------
Other Equatorial United
DECEMBER 31, 1998 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Revenues $564,771 $ $ 10,282 $ 9,105 $25,006 $609,164
Production costs 154,594 2,962 6,274 9,044 172,874
Exploration expenses 90,614 9,987 658 87 5,828 107,174
DD&A and valuation provision 513,725 46 2,998 6,083 13,869 536,721 *
- -----------------------------------------------------------------------------------------------------------------------
Income (loss) (194,162) (10,033) 3,664 (3,339) (3,735) (207,605)
Income tax expense (benefit) (68,764) (2,489) 1,786 (1,822) (794) (72,083)
- -----------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs) $ (125,398) $ (7,544) $ 1,878 $(1,517) $ (2,941) $ (135,522)
- -----------------------------------------------------------------------------------------------------------------------
*Includes a pre-tax charge of $223.3 million pursuant to SFAS No. 121.
</TABLE>
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1997 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Revenues $696,882 $ 9,944 $14,824 $14,777 $24,718 $761,145
Production costs 164,441 4,778 3,600 5,555 8,220 186,594
Exploration expenses 56,177 12,345 3,464 804 7,942 80,732
DD&A and valuation provision 280,862 2,642 1,889 5,037 12,399 302,829
- -----------------------------------------------------------------------------------------------------------------------
Income (loss) 195,402 (9,821) 5,871 3,381 (3,843) 190,990
Income tax expense (benefit) 67,934 (4,470) 4,654 2,680 (3,047) 67,751
- -----------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs) $127,468 $(5,351) $ 1,217 $ 701 $ (796) $123,239
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1996 United States Int'l Guinea Argentina Kingdom TOTAL
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Revenues $548,488 $ 17,602 $17,095 $8,197 $13,206 $604,588
Production costs 118,387 8,179 2,855 2,688 7,015 139,124
Exploration expenses 43,844 11,317 3,738 418 59,317
DD&A and valuation provision 222,426 3,926 2,508 2,057 5,276 236,193
- -----------------------------------------------------------------------------------------------------------------------
Income (loss) 163,831 (5,820) 7,994 3,452 497 169,954
Income tax expense (benefit) 57,873 (4,610) 6,332 2,734 394 62,723
- -----------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs) $105,958 $ (1,210) $ 1,662 $ 718 $ 103 $107,231
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
51
<PAGE> 54
COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)
Costs incurred in connection with the Company's oil and gas
acquisition, exploration and development activities for each of the years are
shown below. Amounts are presented in accordance with SFAS No. 19, and may not
agree with amounts determined using traditional industry definitions.
<TABLE>
<CAPTION>
(in thousands)
Other Equatorial United
DECEMBER 31, 1998 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Property acquisition costs
Proved $ 48,444 $ $ $ $ $ 48,444
Unproved 36,760 500 311 37,571
- -----------------------------------------------------------------------------------------------------------------------
Total $ 85,204 $ 500 $ $ $ 311 $ 86,015
- -----------------------------------------------------------------------------------------------------------------------
Exploration costs $ 132,958 $ 9,663 $ 465 $ 473 $ 5,328 $ 148,887
- -----------------------------------------------------------------------------------------------------------------------
Development costs $ 242,838 $ 10,251 $ 10,977 $7,918 $ 9,761 $ 281,745
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1997 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Property acquisition costs
Proved $ 3,884 $ 28 $ $ $ $ 3,912
Unproved 16,668 3,178 19,846
- -----------------------------------------------------------------------------------------------------------------------
Total $ 20,552 $ 3,206 $ $ $ $ 23,758
- -----------------------------------------------------------------------------------------------------------------------
Exploration costs $ 81,141 $ 14,528 $9,907 $ $ 11,588 $ 117,164
- -----------------------------------------------------------------------------------------------------------------------
Development costs $ 201,788 $ 1,538 $2,871 $5,558 $ 4,213 $ 215,968
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1996 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Property acquisition costs
Proved $ 541,363 $ 65 $ $ 77,158 $ 68,829 $ 687,415
Unproved 24,672 6,782 5,000 9,955 46,409
- -----------------------------------------------------------------------------------------------------------------------
Total $ 566,035 $ 6,847 $ $ 82,158 $ 78,784 $ 733,824
- -----------------------------------------------------------------------------------------------------------------------
Exploration costs $ 81,018 $ 5,813 $3,750 $ $ 418 $ 90,999
- -----------------------------------------------------------------------------------------------------------------------
Development costs $ 176,419 $ 4,184 $ 271 $ 8 $ 3,423 $ 184,305
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
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 are shown
below:
<TABLE>
<CAPTION>
1998 1997
--------------------------------------- ----------------------------------------
(in thousands) U. S. Int'l TOTAL U. S. Int'l TOTAL
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Unproved oil and gas properties $ 86,844 $ 15,302 $ 102,146 $ 57,666 $ 7,190 $ 64,856
Proved oil and gas properties 2,507,767 263,163 2,770,930 2,473,989 227,896 2,701,885
- -----------------------------------------------------------------------------------------------------------------------
2,594,611 278,465 2,873,076 2,531,655 235,086 2,766,741
Accumulated DD&A (1,401,218) (59,357) (1,460,575) (1,201,446) (36,338) (1,237,784)
- -----------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 1,193,393 $ 219,108 $ 1,412,501 $ 1,330,209 $ 198,748 $ 1,528,957
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
52
<PAGE> 55
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, 1998, 1997 and 1996 in accordance with SFAS No. 69.
The Standard requires the use of a 10 percent discount rate. This information
is not the fair market value nor does it represent the expected present value
of future cash flows of the Company's proved oil and gas reserves.
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1998 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
(in millions of dollars)
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows $ 2,647 $ 29 $ 272 $ 96 $ 113 $3,157
Future production and
development costs 1,146 20 120 30 62 1,378
Future income tax expenses 182 1 18 8 6 215
- -----------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,319 8 134 58 45 1,564
10% annual discount for
estimated timing of cash flows 490 3 50 22 17 582
- -----------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 829 $ 5 $ 84 $ 36 $ 28 $ 982
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1997 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
(in millions of dollars)
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows $ 4,330 $ $ 498 $ 196 $ 259 $5,283
Future production and
development costs 2,040 148 121 61 2,370
Future income tax expenses 612 93 20 53 778
- -----------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,678 257 55 145 2,135
10% annual discount for
estimated timing of cash flows 615 95 20 53 783
- -----------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 1,063 $ $ 162 $ 35 $ 92 $1,352
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Other Equatorial United
DECEMBER 31, 1996 United States Int'l Guinea Argentina Kingdom TOTAL
- ------------------------------------------------------------------------------------------------------------------------
(in millions of dollars)
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows $ 6,013 $ 89 $ 206 $ 285 $ 298 $6,891
Future production and
development costs 2,078 33 27 127 174 2,439
Future income tax expenses 1,078 16 51 45 35 1,225
- -----------------------------------------------------------------------------------------------------------------------
Future net cash flows 2,857 40 128 113 89 3,227
10% annual discount for
estimated timing of cash flows 890 12 40 35 28 1,005
- -----------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 1,967 $ 28 $ 88 $ 78 $ 61 $2,222
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
Construction of Samedan's Equatorial Guinea methanol plant is
scheduled to be completed in the first quarter of 2001. The future net cash
inflows for 1998 and 1999 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. "Business--Unconsolidated Subsidiary" and Item 2.
"Properties--Oil and Gas" of this Form 10-K.
53
<PAGE> 56
Future cash inflows are estimated 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 hedging
contracts, if any.
The year-end weighted average oil price utilized in the computation of
future cash inflows was approximately $8.05 per BBL. West Texas intermediate
crude oil price in mid February 1999 was approximately $.25 per BBL lower than
year-end 1998. 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 $63 million.
The year-end weighted average gas price utilized in the computation of
future cash inflows was approximately $2.14 per MCF. Natural gas index prices
at Henry Hub have decreased approximately $.31 per MCF in mid February 1999
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 $65 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 estimated 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, 1998, the Company had estimated gas imbalance
receivables of $19.1 million and estimated gas imbalance liabilities of $14.8
million; at year-end 1997, $18.5 million in receivables and $21.6 million in
liabilities; and at year-end 1996, $19.3 million in receivables and $21.7
million in liabilities. Neither the gas imbalance receivables nor gas imbalance
liabilities have been included in the standardized measure of discounted future
net cash flows as of each of the three years ended December 31, 1998, 1997 and
1996.
54
<PAGE> 57
SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Unaudited)
Principal changes in the aggregate standardized measure of discounted
future net cash flows attributable to the Company's proved oil and gas
reserves, as required by Financial Accounting Standards Board's SFAS No. 69, at
year end are shown below.
<TABLE>
<CAPTION>
(in millions of dollars) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Standardized measure of discounted
future net cash flows at the beginning
of the year $ 1,352 $ 2,222 $ 1,274
Extensions, discoveries and improved
recovery, less related costs 39 501 256
Revisions of previous quantity estimates (132) 13 (76)
Changes in estimated future
development costs (17) (15) (21)
Purchases (sales) of minerals in place 46 (45) 1,043
Net changes in prices and production costs (443) (1,259) 212
Accretion of discount 189 310 178
Sales of oil and gas produced, net of
production costs (454) (594) (475)
Development costs incurred during
the period 127 38 74
Net change in income taxes 503 332 (368)
Change in timing of estimated future
production, and other (228) (151) 125
- -------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the end
of the year $ 982 $ 1,352 $ 2,222
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 1998 and 1997
is as follows:
<TABLE>
<CAPTION>
Quarter Ended
-----------------------------------------------------------------
(in thousands except per share amounts) Mar. 31, June 30, Sept. 30, Dec. 31,(1)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998
Revenues $ 246,535 $ 237,392 $ 205,803 $ 203,841
Gross profit from operations $ 31,838 $ 27,326 $ (25,616) $ (235,922)
Net income $ 13,718 $ 12,135 $ (25,150) $ (164,728)
Basic earnings per share $ .24 $ .21 $ (.44) $ (2.89)
Diluted earnings per share $ .24 $ .21 $ (.44) $ (2.89)
1997
Revenues $ 319,432 $ 232,881 $ 231,983 $ 306,717
Gross profit from operations $ 74,512 $ 28,706 $ 32,635 $ 45,149
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
</TABLE>
(1) During the fourth quarters of 1998 and 1997, DD&A expense increased $9.8
million and $5.5 million, respectively, relating to the cumulative effect
of oil and gas reserve revisions on the DD&A provision for the preceding
three quarters.
55
<PAGE> 58
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The section entitled "Election of Directors" in the Registrant's proxy
statement for the 1999 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 1999 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 1999 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 1999 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 1999 annual meeting of stockholders sets forth certain
information with respect to certain relationships and related transactions, and
is incorporated herein by reference.
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 and
Supplementary Data: 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) A Form 8-K was filed by the Registrant on December 14, 1998,
relating to Amendment No. 1 to the Company's Rights Agreement.
56
<PAGE> 59
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 15, 1999 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.
<TABLE>
<CAPTION>
Signature Capacity in which signed Date
- --------- ------------------------ ----
<S> <C> <C>
/s/ Robert Kelley Chairman of the Board, President, March 15, 1999
- ------------------------------------ Chief Executive Officer and
Robert Kelley Director (Principal Executive
Officer)
/s/ William D. Dickson Senior Vice President-Finance and March 15, 1999
- ------------------------------------ Treasurer (Principal Financial Officer)
William D. Dickson
/s/ James L. McElvany Vice President and Controller March 15, 1999
- ------------------------------------ (Principal Accounting Officer)
James L. McElvany
/s/ Alan A. Baker Director March 15, 1999
- ------------------------------------
Alan A. Baker
/s/ Michael A. Cawley Director March 15, 1999
- ------------------------------------
Michael A. Cawley
/s/ Edward F. Cox Director March 15, 1999
- ------------------------------------
Edward F. Cox
/s/ James C. Day Director March 15, 1999
- ------------------------------------
James C. Day
/s/ Thomas E. Hassen Director March 15, 1999
- ------------------------------------
Thomas E. Hassen
/s/ Dale P. Jones Director March 15, 1999
- ------------------------------------
Dale P. Jones
/s/ Harold F. Kleinman Director March 15, 1999
- ------------------------------------
Harold F. Kleinman
/s/ George J. McLeod Director March 15, 1999
- ------------------------------------
George J. McLeod
/s/ T. Don Stacy Director March 15, 1999
- ------------------------------------
T. Don Stacy
</TABLE>
57
<PAGE> 60
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit
Number Exhibit **
- ------- -------
<S> <C>
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 -- Composite copy of Bylaws of the Registrant as currently in
effect (filed as Exhibit 3.4 to the Registrants' Annual Report
on Form 10-K for the year ended December 31, 1997 and
incorporated herein by reference).
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,
1997 and incorporated herein by reference).
4.5 -- Rights Agreement, dated as of August 27, 1997, between the
Registrant and Liberty Bank and Trust Company of Oklahoma City,
N.A., as Right's Agent (filed as Exhibit 4.1 to the
Registrant's Registration Statement on Form 8-A filed on August
28, 1997 and incorporated herein by reference).
4.6 -- Amendment No. 1 to Rights Agreement dated as of December 8,
1998, between the Registrant and Bank One Trust Company, as
successor Rights Agent to Liberty Bank and Trust Company of
Oklahoma City, N.A. (filed as Exhibit 4.2 to the Registrant's
Registration Statement on Form 8-A/A (Amendment No. 1) filed on
December 14, 1998 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). Exhibit Number Exhibit **
</TABLE>
<PAGE> 61
<TABLE>
<CAPTION>
Exhibit
Number Exhibit **
- ------- -------
<S> <C>
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).
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* -- 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).
10.10* -- 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).
10.11 -- 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).
10.12 -- 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).
10.13* -- 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).
10.14 -- 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 (filed as
Exhibit 10.20 to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997 and incorporated
herein by reference).
21 -- Subsidiaries.
</TABLE>
<PAGE> 62
<TABLE>
<CAPTION>
Exhibit
Number Exhibit **
- ------- -------
<S> <C>
23 -- Consent of Arthur Andersen LLP.
27.1 -- Financial Data Schedule.
27.2 -- Restated Financial Data Schedule.
</TABLE>
- ---------------
* 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.
<PAGE> 1
Exhibit 21
to Form 10-K
SUBSIDIARIES
<TABLE>
<CAPTION>
State or Jurisdiction of
Name Organization Ownership %
- ---- ------------------------ -----------
<S> <C> <C>
Samedan Oil Corporation Delaware 100% owned by Noble Affiliates, Inc.
Samedan Oil of Canada, Inc. Delaware 100% owned by Samedan Oil Corporation
Samedan of North Africa, Inc. Delaware 100% owned by Samedan Oil Corporation
Samedan Mediterranean Sea Cayman Islands 100% owned by Samedan Oil Corporation
Samedan International Cayman Islands 100% owned by Samedan of North Africa
Samedan Methanol Cayman Islands 100% owned by Samedan International
Samedan North Sea, Inc. Delaware 100% owned by Samedan Oil Corporation
Samedan Oil of Indonesia, Inc. Delaware 100% owned by Samedan Oil Corporation
Samedan Pipe Line Corporation Delaware 100% owned by Samedan Oil Corporation
Samedan Royalty Corporation Delaware 100% owned by Samedan Oil Corporation
Samedan of Tunisia, Inc. Delaware 100% owned by Samedan Oil Corporation
Samedan, Mediterranean Sea, Inc. Delaware 100% owned by Samedan Oil Corporation
Noble Gas Marketing, Inc. Delaware 100% owned by Noble Affiliates, Inc.
Noble Gas Pipeline, Inc. Delaware 100% owned by Noble Gas Marketing, Inc.
Noble Trading, Inc. Delaware 100% owned by Noble Affiliates, Inc.
NPM, Inc. Delaware 100% owned by Noble Affiliates, Inc.
Energy Development Corporation New Jersey 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Energy Development Corporation Delaware 100% owned (direct or indirect) by Noble
(Argentina), Inc. Affiliates, Inc.
Energy Development Corporation Delaware 100% owned (direct or indirect) by Noble
(China), Inc. Affiliates, Inc.
EDC Denmark 100% owned (direct or indirect) by Noble
Affiliates, Inc.
</TABLE>
1
<PAGE> 2
<TABLE>
<CAPTION>
State or Jurisdiction of
Name Organization Ownership %
- ---- ------------------------ -----------
<S> <C> <C>
Energy Development Corporation Delaware 100% owned (direct or indirect) by Noble
(HIPS), Inc. Affiliates, Inc.
Energy Development Corporation Delaware 100% owned (direct or indirect) by Noble
(Peru), Inc. Affiliates, Inc.
EDC (Tunisia), Inc. Delaware 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC Ecuador Ltd. Delaware 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC Ecuador Limited Cayman Islands 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC Senegal, Ltd. Delaware 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC Australia, Ltd. Delaware 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC Portugal, Ltd. Delaware 100% owned (direct or indirect )by Noble
Affiliates, Inc.
Gasdel Pipeline System, Incorporated New Jersey 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Producers Services, Inc. New Jersey 100% owned (direct or indirect) by Noble
Affiliates, Inc.
HGC, Inc. Delaware 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Pelto Oil Company, Inc. New Jersey 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC (UK) Ltd. Delaware 100% owned (direct or indirect) by Noble
Affiliates, Inc.
EDC (Europe) Limited, formerly
Brabant Petroleum, Limited United Kingdom 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Industrial Scotland Energy Ltd. United Kingdom 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Brabant Oil Ltd. United Kingdom 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Brabant Oilex Ltd. United Kingdom 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Brabant Petroleum USA Company Kansas 100% owned (direct or indirect) by Noble
Affiliates, Inc.
Burnside Overseas Exploration United Kingdom 100% owned (direct or indirect) by Noble
Limited Affiliates, Inc.
</TABLE>
2
<PAGE> 3
<TABLE>
<CAPTION>
State or Jurisdiction of
Name Organization Ownership %
- ---- ------------------------ -----------
<S> <C> <C>
EDC Marketing Company United Kingdom 100% owned (direct or indirect) by Noble
Affiliates, Inc.
</TABLE>
3
<PAGE> 1
EXHIBIT 23
ARTHUR ANDERSEN LLP
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated January 29, 1999, included on page 32 of the Company's 1998 Form
10-K, into the previously filed registration statements on Form S-3 (File No.
333-18929) and on Form S-8 (File Nos. 333-39299, 2-64600, 2-81590, 33-32692,
2-66654 and 33-54084).
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
March 24, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 19,100
<SECURITIES> 0
<RECEIVABLES> 106,513
<ALLOWANCES> 0
<INVENTORY> 3,006
<CURRENT-ASSETS> 188,289
<PP&E> 2,915,917
<DEPRECIATION> (1,486,250)
<TOTAL-ASSETS> 1,686,080
<CURRENT-LIABILITIES> 139,166
<BONDS> 745,143
0
0
<COMMON> 195,018
<OTHER-SE> 462,480
<TOTAL-LIABILITY-AND-EQUITY> 1,686,080
<SALES> 609,164
<TOTAL-REVENUES> 911,616
<CGS> 0
<TOTAL-COSTS> 884,562
<OTHER-EXPENSES> 223,251
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 50,511
<INCOME-PRETAX> (246,708)
<INCOME-TAX> (82,683)
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (164,025)
<EPS-PRIMARY> (2.88)
<EPS-DILUTED> (2.88)
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 94,768
<SECURITIES> 0
<RECEIVABLES> 206,151
<ALLOWANCES> 0
<INVENTORY> 4,489
<CURRENT-ASSETS> 316,803
<PP&E> 2,571,964
<DEPRECIATION> (1,000,200)
<TOTAL-ASSETS> 1,956,938
<CURRENT-LIABILITIES> 279,806
<BONDS> 798,028
0
0
<COMMON> 194,402
<OTHER-SE> 541,083
<TOTAL-LIABILITY-AND-EQUITY> 1,956,938
<SALES> 604,588
<TOTAL-REVENUES> 887,203
<CGS> 0
<TOTAL-COSTS> 712,440
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 38,474
<INCOME-PRETAX> 136,289
<INCOME-TAX> 52,409
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 83,880
<EPS-PRIMARY> 1.63<F1>
<EPS-DILUTED> 1.55
<FN>
<F1>THE COMPANY ADOPTED THE PROVISIONS OF THE SFAS NO. 128 IN THE PREPARATION OF
THE FINANCIAL STATEMENTS INCLUDED IN THE ANNUAL REPORT ON FORM 10-K FOR THE
PERIOD ENDED DECEMBER 31, 1997. IN ACCORDANCE WITH THE PROVISIONS OF SFAS NO.
128, THE COMPANY HAS RESTATED PREVIOUSLY REPORTED EARNINGS PER SHARE AMOUNTS TO
CONFORM TO THE PROVISIONS OF SFAS NO. 128.
</FN>
</TABLE>
