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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: 1-12534
NEWFIELD EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
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State of incorporation: Delaware I.R.S. Employer Identification No. 72-1133047
363 N. Sam Houston Parkway E.
Suite 2020
Houston, Texas 77060
(Address of principal executive offices) (Zip code)
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Registrant's telephone number, including area code: 281-847-6000
Securities Registered pursuant to Section 12(b) of the Act:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, Par Value $0.01 Per Share New York Stock Exchange
Rights to Purchase Series A Junior Participating Preferred Stock, New York Stock Exchange
Par Value $0.01 Per Share
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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.
[x] Yes [ ] 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]
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $362,432,000 as of February 26, 1999
(based on the last sale price of such stock as quoted on the New York Stock
Exchange).
As of February 28, 1999 there were 40,463,353 shares of the
registrant's Common Stock, par value $0.01 per share, outstanding.
Documents incorporated by reference: 1998 Annual Report to Stockholders
of Newfield Exploration Company, which is incorporated into Part II of this Form
10-K and Proxy Statement of Newfield Exploration Company for the Annual Meeting
of Stockholders to be held on May 5, 1999, which is incorporated into Part III
of this Form 10-K.
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TABLE OF CONTENTS
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PART I
Item 1. Business.................................................................................. 1
Item 2. Properties................................................................................ 8
Item 3. Legal Proceedings......................................................................... 15
Item 4. Submission of Matters to a Vote of Security Holders....................................... 15
Item 4A. Executive Officers of the Registrant...................................................... 15
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..................... 16
Item 6. Selected Financial Data................................................................... 16
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................................... 16
Item 8. Financial Statements and Supplementary Data............................................... 17
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................................ 17
PART III
Item 10. Directors and Executive Officers of the Registrant........................................ 18
Item 11. Executive Compensation.................................................................... 18
Item 12. Security Ownership of Certain Beneficial Owners and Management............................ 18
Item 13. Certain Relationships and Related Transactions............................................ 18
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........................... 18
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PART I
ITEM 1. BUSINESS
OVERVIEW
Newfield Exploration Company ("Newfield" or the "Company") is an
independent oil and gas company engaged in the exploration, development and
acquisition of oil and natural gas properties located primarily in the Gulf of
Mexico. The Company discovered and acquired its first oil and gas reserves in
1990 and has grown rapidly since that time. At December 31, 1998 the Company had
proved reserves of 513.3 Bcfe consisting of 15.2 MMBbls of oil and condensate
and 422.3 billion cubic feet ("Bcf") of natural gas. Approximately 82% of the
Company's proved reserves at such date were natural gas and approximately 93%
were proved developed. Unless otherwise noted, all information in this Form 10-K
relating to oil and gas reserves and the estimated future net cash flows
attributable thereto are based upon estimates prepared by the Company and are
net to the Company's interest. See "Item 2. Properties - Oil and Gas Reserves."
Certain terms relating to the oil and gas business are defined under the caption
"Oil and Gas Terms" at the end of Item 2.
STRATEGY
Newfield's strategy is to continue to expand its reserve base and
increase its cash flow through exploration and the acquisition and exploitation
of proved properties. The Company emphasizes the following elements in
implementing this strategy:
o Reserve growth through exploratory drilling of a balanced portfolio
o Balance between exploration and the acquisition and exploitation of
proved properties
o Geographic focus
o Control of operations and costs
o Use of 3-D seismic and other advanced technology
o Equity ownership and other incentives to attract and retain employees
Newfield has utilized a balanced approach of exploration and the
acquisition and exploitation of proved properties to grow its reserves,
production and cash flow. Of the 872.5 Bcfe of proved reserves Newfield added
through December 31, 1998, 35% were added through exploration, 40% were added
through the acquisition of proved reserves and 25% were added through the
exploitation of opportunities identified and acquired in connection with the
acquisition of proved properties. Newfield's exploration, acquisition and
exploitation activities are complementary. Proved properties acquired by
Newfield usually have exploration or exploitation potential that Newfield has
previously identified. In addition, acquisitions can increase Newfield's
presence in an area, creating the infrastructure to provide Newfield with the
ability to capture other opportunities at a competitive advantage. Information
gathered while evaluating production on acquisition candidates and adjacent
acreage is used, as appropriate, in Newfield's exploration efforts. Conversely,
a successful exploratory prospect may reveal similar untested reserve potential
on an adjacent property, making its purchase attractive.
EXPLORATION ACTIVITIES. The Company maintains an active,
technologically driven exploration program conducted by five multi-disciplined
teams focused on distinct geological trends in the Gulf of Mexico, the onshore
Gulf Coast and selected international areas. During 1998 the Company invested
$65.3 million in exploration activities. The Company allocates its exploration
spending between a small number of higher risk, higher potential prospects
which, if successful, may result in significant increases in proved reserves,
and a greater number of lower risk, moderate potential prospects. From its
inception through December 31, 1998, the Company participated in the drilling of
107 exploratory wells at a cost to drill and evaluate of $202.6 million, net to
Newfield's interest. These wells have resulted in the discovery of equivalent
proved reserves of 310.5 Bcfe, net to Newfield's interest. All but 21 of these
wells were operated by the Company. Sixty-five of the wells operated by the
Company were drilled under turnkey drilling contracts.
Newfield acquires exploration prospects through federal and state lease
sales, in connection with proved property acquisitions and through farm-ins.
Newfield is continuously evaluating new opportunities and currently has a
substantial inventory of prospects, including 12 to 15 that are expected to be
drilled in 1999.
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ACQUISITION ACTIVITIES. The Company actively pursues the acquisition of
proved oil and gas properties in the Gulf of Mexico, the onshore Gulf Coast and
select international areas, particularly properties with unexploited reserve
potential in order to enhance returns. The Company looks for properties that it
can operate in order to better control operations and costs and in which it can
increase its interest. Acquisition properties that meet these criteria and
provide a base for further evaluation and exploitation adjacent to production
already established by the Company are of particular interest to the Company.
The Company pursues a multi-discipline team approach for evaluating acquisition
opportunities. Potential acquisitions undergo extensive technical and financial
evaluation by a group of geologists, geophysicists, geological engineers and
petroleum engineers. Land, drilling, operations and marketing staffs support
these evaluation efforts. The Company's seismic, land and production databases,
along with regional geological interpretations, supplement any information
provided by a potential seller in the acquisition candidate screening process.
DEVELOPMENT ACTIVITIES. Newfield also maintains an active development
program. During 1998, Newfield invested $155.8 million for development costs,
including recompletions and development drilling. From its inception through
December 31, 1998, Newfield participated in 121 development wells at an
aggregate cost of $353.7 million, net to Newfield's interest. These wells have
resulted in the addition of proved reserves of 212 Bcfe.
GEOGRAPHIC FOCUS. The Company believes that its focus in the federal
waters of the Gulf of Mexico, primarily offshore Louisiana in shallow water, is
the foundation for its continued growth. The Gulf of Mexico is a prolific oil
and gas province, accounting for approximately 25% of domestic natural gas
production, and the Company believes that it has significant remaining
undiscovered reserve potential. Newfield's management and technical personnel
have extensive experience in the Gulf of Mexico, and Newfield's geographic focus
assists it in controlling operating and administrative costs. The Gulf of Mexico
has a substantial existing infrastructure, including gathering systems,
platforms and pipelines, and numerous drilling and service companies maintain a
substantial presence there, facilitating cost effective operations and the
timely development of discoveries. In addition, significant amounts of geologic
data, including 3-D seismic data, are available at reasonable cost.
While Newfield intends to continue to focus on the Gulf of Mexico, it
also intends to pursue selective opportunities to develop "focused
diversification" outside the Gulf of Mexico. Focused diversification efforts
will be directed toward a limited number of areas where Newfield can apply its
core competencies, such as geological and geophysical analyses through the
application of 3-D seismic and other advanced technologies, expertise in marine
operations and control of or significant influence on operations.
Building on its core competencies, Newfield established onshore Gulf
Coast operations in 1995 as a natural extension of its offshore effort. To date,
Newfield's onshore efforts have been focused in southern Louisiana and the Texas
Gulf Coast. Newfield has acquired interests in 540 square miles of 3-D seismic
data and approximately 38,000 gross acres on the onshore Gulf Coast. Two of
three exploration wells drilled in 1998 on the onshore Gulf Coast have resulted
in discoveries, one of which commenced production in August 1998.
In 1997, Newfield made its initial international investment by
acquiring a 35% interest in a 415,000 acre production sharing license in the
Bohai Bay, offshore China. Although, the first exploratory well on the block was
plugged and abandoned, exploration operations are continuing on the block.
Successful exploratory drilling in the Bohai Bay may result in significant
future investment in the area. The approved 1999 work program and budget for the
Bohai Bay includes a 3-D seismic survey and one exploratory well. Newfield
continues to evaluate new opportunities for international expansion in areas in
which it can utilize its core competencies. Newfield believes such areas include
offshore China, offshore West Africa and the Northwest Shelf, offshore
Australia.
CONTROL OF OPERATIONS AND COSTS. The Company prefers to operate its
properties in order to manage production performance and to control operating
expenses, the timing and amount of capital expenditures and the application of
technology. Properties operated by the Company accounted for 85% of its total
equivalent production for 1998. Newfield's geographic focus enables it to manage
a large asset base with a relatively small number of employees and to add
successful exploratory and development wells and proved property acquisitions at
relatively low incremental costs. Newfield also uses independent contractors for
much of its field operations activities to control costs.
TECHNOLOGY. Newfield uses advanced technology in its exploration and
development activities to reduce its risks and lower its costs. Newfield
currently holds licenses or has access to 3-D seismic surveys covering
approximately
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2,200 blocks (approximately 11.3 million acres) in the Gulf of Mexico and 540
square miles in southern Louisiana and Texas, including coverage of all of the
producing fields it operates. In addition, Newfield holds licenses or has
access to more than 380,000 miles of recent vintage conventional seismic data
in the Gulf of Mexico and owns a library containing logs on more than 4,500
wells drilled in Newfield's focus area.
MANAGEMENT AND EMPLOYEES. Newfield's management and 44 technical
personnel have extensive experience in the Gulf of Mexico. In order to attract
and retain its employees, the Company provides incentives through equity
ownership and other benefit plans. As of December 31, 1998, the Company's
employees owned or had options to acquire an aggregate of approximately 11% of
the Company's outstanding Common Stock, par value $0.01 per share ("Common
Stock"), on a fully diluted basis.
MARKETING
The Company markets substantially all of the oil and gas production
from Company operated properties for both the account of the Company and the
other working interest owners in these properties. Substantially all of the
Company's natural gas production is sold to a variety of purchasers under
short-term (less than 12 months) contracts or 30-day spot gas purchase
contracts. During 1998, Conoco Inc., Superior Natural Gas Corporation and Coast
Energy Group each purchased in excess of 10% of the gas sold by the Company for
its own account. Oil sales contracts are short-term and are based upon field
posted prices plus negotiated bonuses. During 1998, Gulfmark Energy, Inc.,
Equilon Enterprises LLC, and Chevron USA Inc. each purchased in excess of 10% of
the oil sold by the Company for its own account. Because alternative purchasers
of oil and gas are readily available, the Company believes that the loss of any
of these purchasers would not have a material adverse effect on the Company. See
Note 1 to the Company's consolidated financial statements.
VOLATILITY OF OIL AND GAS PRICES AND HEDGING
As an independent oil and gas producer, the Company's revenue,
profitability and future rate of growth are substantially dependent upon the
prevailing prices of, and demand for, natural gas, oil and condensate. The
Company's ability to maintain or increase its borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent upon oil
and gas prices. Prices for oil and natural gas are subject to wide fluctuation
in response to relatively minor changes in the supply of, and demand for, oil
and gas, market uncertainty and a variety of additional factors that are beyond
the control of the Company. These factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels, political conditions in oil and gas
producing regions worldwide, the foreign supply of oil and natural gas, the
price of oil and gas imports and overall economic factors. From time to time,
oil and gas prices have been depressed by excess domestic and imported supplies.
Prices for oil and gas have recently declined materially. It is impossible to
predict future oil and natural gas price movements with any certainty. Any
continued and extended decline in the price of oil or gas could have a material
adverse effect on the Company's financial position, cash flows and results of
operations and may reduce the amount of the Company's oil and natural gas that
can be produced economically. Additionally, substantially all of the Company's
sales of oil and natural gas are made in the spot market or pursuant to
contracts based on spot market prices and not pursuant to long-term fixed price
contracts.
The Company has utilized and expects to continue to utilize hedging
transactions with respect to a portion of its oil and gas production to achieve
a more predictable cash flow, as well as to reduce its exposure to price
fluctuations. While the use of these hedging arrangements limits the downside
risk of adverse price movements, they may also limit future revenues from
favorable price movements. The use of hedging transactions also involves the
risk that the counterparties will be unable to meet the financial terms of such
transactions. All of the Company's hedging transactions to date were carried out
in the over-the-counter market and the obligations of the counterparties have
been guaranteed by entities with at least an investment grade rating or secured
by letters of credit. The Company accounts for these transactions as hedging
activities and, accordingly, gains or losses are included in oil and gas
revenues when the hedged production is delivered. Neither the hedging contracts
nor the unrealized gains or losses on these contracts are recognized in the
financial statements.
During 1998, approximately 61% of Newfield's equivalent production was
subject to hedge positions as compared to 64% in 1997. Newfield has also entered
into hedging transactions with respect to a portion of its estimated
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production through December 2000. For a discussion of the various hedges
existing at December 31, 1998, see Note 2 to the Company's consolidated
financial statements. Newfield continues to evaluate whether to enter into
additional hedging transactions for 1999 and future years. In addition,
Newfield may determine from time to time to terminate a portion of its then
existing hedging positions.
CEILING TEST WRITEDOWNS
The Company uses the full cost method of accounting. Under this method,
all costs incurred in the acquisition, exploration and development of oil and
gas properties are capitalized into cost centers that are established on a
country-by-country basis. For each cost center, at the end of each quarter, the
net capitalized costs of oil and gas properties are limited to the lower of
unamortized cost of the cost center ceiling, defined as the sum of the present
value (10% discount rate) of estimated future net revenues from proved
reserves, based on period-end oil and gas prices; plus the cost of properties
not being amortized, if any; plus the lower of cost or estimated fair value of
unproved properties included in the costs being amortized, if any; less related
income tax effects. If net capitalized costs of oil and gas properties exceed
the ceiling limit, the Company is subject to a ceiling test writedown to the
extent of such excess. A ceiling test writedown is a charge to earnings that
does not impact cash flows. Such writedowns do, however, impact stockholders'
equity. The risk that the Company will be required to write down the carrying
value of its oil and gas properties increases when oil and gas prices are
depressed or volatile. Application of these rules during periods of relatively
low oil or gas prices, even if temporary, increases the probability of a
ceiling test writedown. In addition, writedowns may occur if the Company makes
additional acquisitions or has substantial downward revisions in its estimated
proved reserves. Primarily as a result of the recent significant declines in
both oil and gas prices, the Company recorded a ceiling test writedown at
December 31, 1998 of $105.0 million (see Note 1 to the Company's consolidated
financial statements). The continued decline in both oil and gas prices since
December 31, 1998 may require the Company to record an additional ceiling test
writedown in the first quarter of 1999. See "--- Volatility of Oil and Gas
Prices and Hedging." No assurance can be given that the Company will not
experience a ceiling test writedown in future periods.
COMPETITION
Competition in the oil and gas industry is intense, particularly with
respect to the acquisition of producing properties and proved undeveloped
acreage. Major and independent oil and gas companies actively bid for desirable
oil and gas properties, as well as for the equipment and labor required to
operate and develop such properties. The Company believes that its geographic
focus, its exploration, drilling and production capabilities, and the experience
of its management generally enable it to compete effectively. Many of the
Company's competitors, however, have financial resources and exploration and
development budgets that are substantially greater than those of the Company,
which may adversely affect the Company's ability to compete with these
companies.
REGULATION
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938
(the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations
promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC").
In the past, the federal government has regulated the prices at which gas could
be sold. Deregulation of wellhead natural gas sales began with the enactment of
the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act"). The Decontrol Act removed all NGA and NGPA price and non-price
controls affecting wellhead sales of natural gas effective January 1, 1993.
Congress could, however, reenact price controls in the future.
The Company's sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to pipeline
transportation remain subject to extensive federal and state regulation. Several
major regulatory changes have been implemented by Congress and the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC is continually proposing and
implementing new rules and regulations affecting those segments of the natural
gas industry, most notably interstate natural gas transmission companies, that
remain subject to the FERC's jurisdiction. These initiatives may also affect the
intrastate transportation of gas under certain circumstances. The stated purpose
of many of these regulatory changes
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is to promote competition among the various sectors of the natural gas industry
and these initiatives generally reflect more light-handed regulation of the
natural gas industry.
The ultimate impact of the complex rules and regulations issued by the
FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial and
FERC final decisions.
The Company cannot predict what further action the FERC will take on
these matters. Some of the FERC's more recent proposals may, however, adversely
affect the availability and reliability of interruptible transportation service
on interstate pipelines. The Company does not believe that it will be affected
by any action taken materially differently than other natural gas producers,
gatherers and marketers with which it competes.
The Outer Continental Shelf Lands Act (the "OCSLA") requires that all
pipelines operating on or across the Outer Continental Shelf (the "OCS") provide
open-access, non-discriminatory service. Although the FERC has opted not to
impose the regulations of Order No. 509, in which the FERC implemented the
OCSLA, on gatherers and other non-jurisdictional entities, the FERC has retained
the authority to exercise jurisdiction over those entities if necessary to
permit non-discriminatory access to service on the OCS.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
FEDERAL LEASES. Substantially all of the Company's operations are
located on federal oil and gas leases, which are administered by the MMS. Such
leases are issued through competitive bidding, contain relatively standardized
terms and require compliance with detailed MMS regulations and orders pursuant
to the OCSLA (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency), lessees must obtain a permit
from the MMS prior to the commencement of drilling. The MMS has promulgated
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specifications. The MMS also has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities. To cover the various obligations of
lessees on the OCS, the MMS generally requires that lessees have substantial net
worth or post bonds or other acceptable assurances that such obligations will be
met. The cost of such bonds or other surety can be substantial and there is no
assurance that bonds or other surety can be obtained in all cases. The Company
is currently exempt from the supplemental bonding requirements of the MMS. Under
certain circumstances, the MMS may require any Company operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition, cash flows
and results of operations.
The MMS has issued a notice of proposed rulemaking in which it proposes
to amend its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. This proposed rule would
modify the valuation procedures for both arm's-length and non-arm's-length crude
oil transactions, establish a new MMS form for collecting value differential
data, and amend the valuation procedure for the sale of federal royalty oil. The
Company cannot predict what action the MMS will take on this matter. The Company
believes that these rules, if adopted as proposed, will not have a material
effect on its financial position, cash flows or results of operations.
The MMS recently implemented a final rule that describes the types of
transportation components that are deductible for calculating and reporting
royalties, as well as various cost components associated with marketing
functions that are not deductible. In particular, under the rule, the MMS will
not allow deduction of costs associated with marketer fees, cash out and other
gas pipeline imbalance penalties, or long-term storage fees. The Company cannot
predict at this time how it might be affected by implementation of the new
rule.
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The MMS periodically investigates whether it has received the
appropriate amount of royalties associated with production on particular MMS
leases. The Company is not aware of any investigation by the MMS with respect to
any leases in which the Company owns an interest, but the MMS has scheduled an
audit of the Company in March 1999.
Finally, the MMS is conducting an inquiry (not specifically directed at
the Company) into certain contractual agreements from which producers on MMS
leases have received settlement proceeds that are royalty bearing and the extent
to which producers have paid the appropriate royalties on those proceeds. The
Company believes that this inquiry will not have a material effect on its
financial position, cash flows or results of operations.
STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION. The Company owns
interests in properties located in onshore Louisiana and Texas and in the state
waters of the Gulf of Mexico offshore Texas and Louisiana and occasionally may
conduct operations in the state waters offshore Mississippi. These states
regulate drilling and operating activities by requiring, among other things,
drilling permits and bonds and reports concerning operations. The laws of these
states also govern a number of environmental and conservation matters, including
the handling and disposing of waste materials, unitization and pooling of oil
and gas properties and establishment of maximum rates of production from oil and
gas wells. Some states prorate production to the market demand for oil and gas.
ENVIRONMENTAL REGULATIONS. The Company's operations are subject to
numerous laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Failure to comply
with these laws and regulations may result in the assessment of administrative,
civil and criminal penalties. Public interest in the protection of the
environment has increased dramatically in recent years. Offshore drilling in
certain areas has been opposed by environmental groups and, in certain areas,
has been restricted. To the extent laws are enacted or other governmental action
is taken that prohibits or restricts offshore drilling or imposes environmental
protection requirements that result in increased costs to the oil and gas
industry in general and the offshore drilling industry in particular, the
business and prospects of the Company could be adversely affected.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills in
United States waters. A "responsible party" includes the owner or operator of an
onshore facility, vessel or pipeline, or the lessee or permittee of the area in
which an offshore facility is located. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages. While liability limits apply in some circumstances, a party cannot take
advantage of liability limits if the spill was caused by gross negligence or
willful misconduct or resulted from violation of a federal safety, construction
or operating regulation. If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. Even if
applicable, the liability limits for offshore facilities require the responsible
party to pay all removal costs, plus up to $75 million in other damages. Few
defenses exist to the liability imposed by the OPA. Failure to comply with
ongoing requirements or inadequate cooperation during a spill event may subject
a responsible party to civil or criminal enforcement actions. In addition to the
OPA, the Company's discharges to waters of the United States are further limited
by the federal Clean Water Act (the "CWA") and analogous state laws. The CWA
prohibits any discharge into waters of the United States except in strict
conformance with permits issued by federal and state governmental agencies.
Failure to comply with the CWA, including discharge limits on permits issued
pursuant to the CWA, may also result in civil or criminal enforcement actions.
The OPA and the CWA also impose other requirements, such as the preparation of
an oil spill response plan. The Company has such a plan in place.
The OPA requires responsible parties to demonstrate proof of financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill. As amended by the Coast Guard
Authorization Act of 1996, the OPA requires responsible parties for offshore
facilities to provide financial assurance in the amount of $35 million to cover
potential OPA liabilities. This amount can be increased up to $150 million
based on a covered facility's potential worst case oil spill discharge volume
or if a formal risk assessment indicates that an amount higher than $35 million
should be required. On August 11, 1998 , the MMS issued its new rule
implementing these OPA financial responsibility requirements. The Company must
comply with the new OPA financial responsibility requirements by April 8, 1999,
or the earliest date that an existing Certificate of Financial Responsibility
for any covered facility expires. The Company does not anticipate that it will
experience any difficulty in satisfying the MMS's requirements for
demonstrating financial responsibility for its covered facilities.
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In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to the OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or private prosecution.
The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site.
Persons who are or were responsible for releases of hazardous
substances under CERCLA may be subject to joint and several liability for the
costs of cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.
In addition, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas exploration and production wastes
as "hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could increase the operating costs of the Company, as
well as the oil and gas industry in general.
Management believes that the Company is in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect on
the Company's financial position, cash flows or results of operations.
RISKS OF FOREIGN OPERATIONS
While the Company intends to continue to focus on the Gulf of Mexico
and the onshore Gulf Coast, the Company also intends to pursue selective
opportunities to develop "focused diversification" outside of such areas. In
1997, the Company made its initial international investment by acquiring a 35%
interest in a 415,000 acre production sharing license in the Bohai Bay, offshore
China, from Huffco International, L.L.C. ("Huffco"). Although the first
exploratory well on the block was plugged and abandoned, exploration operations
are continuing on the block. Successful exploratory drilling in the Bohai Bay
may result in significant future investment in the area. The approved 1999 work
program and budget for the Bohai Bay includes a 3-D seismic survey and one
exploratory well. Huffco retained a preferred stock interest in the subsidiary
of the Company that owns the interest in the Bohai Bay production sharing
license. Such preferred stock interest is economically similar to a 10% net
profits interest in the Bohai Bay activities of such subsidiary. A director and
an executive officer of Newfield together hold in excess of 90% of the
outstanding member interests of Huffco.
The Company continues to evaluate new opportunities for international
expansion in areas in which it can utilize its core competencies. The Company
believes such areas include offshore China, offshore West Africa and the
Northwest Shelf, offshore Australia. Ownership of property interests and
production operations in China, and in any other areas outside the United
States in which the Company may choose to do business, are subject to the
various risks inherent in foreign operations. These risks may include, among
other things, currency restrictions and exchange rate fluctuations, loss of
revenue, property and equipment as a result of hazards such as expropriation,
nationalization, war, insurrection and other political risks, risks of
increases in taxes and governmental royalties, renegotiation of contracts with
governmental entities and quasi-governmental agencies, change in laws and
policies governing operations of foreign-based companies and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. The Company's international operations may also be
adversely affected by laws and policies of the United States affecting foreign
trade, taxation and investment. In addition, in the event of a dispute arising
from foreign operations, the Company may be subject to the exclusive
jurisdiction of foreign courts or may not be successful in subjecting foreign
persons to the jurisdiction of the courts of the United States.
-7-
<PAGE> 10
OPERATING HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to
the drilling of oil and gas wells, many of which are beyond the Company's
control, such as cratering, explosions, uncontrollable flows of oil, gas or well
fluids, fires, pollution and other environmental risks. Additional risks include
the risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled as a result
of numerous factors including title problems, compliance with governmental
requirements and shortages or delays in the delivery of equipment. In addition
to the foregoing, substantially all of the Company's operations currently are
offshore and subject to the additional hazards of marine operations, such as
capsizing, collision and damage or loss from severe weather.
These hazards can cause personal injury and loss of life, severe damage
to and destruction of property and equipment, environmental damage and
suspension of operations.
In accordance with customary industry practice, the Company maintains
insurance against some, but not all, of the risks described above. The Company's
insurance does not fully cover business interruption or protect against loss of
revenues. There can be no assurance that any insurance obtained by the Company
will be adequate to cover any losses or liabilities. The Company cannot predict
the continued availability of insurance or the availability of insurance at
premium levels that justify its purchase. The occurrence of a significant event
not fully insured or indemnified against could materially and adversely affect
the Company's financial position, cash flows and operations.
EMPLOYEES
At February 15, 1999 the Company had 96 full time employees, primarily
professionals, including geologists, geophysicists, and engineers. The Company
believes that its relationships with its employees are satisfactory. None of the
Company's employees are covered by a collective bargaining agreement. From time
to time, the Company utilizes the services of independent consultants and
contractors to perform various professional services, particularly in the areas
of construction, design, well site surveillance, permitting and environmental
assessment. Field and on-site production operation services, such as pumping,
maintenance, dispatching, inspection and testing, are generally provided by
independent contractors.
FORWARD-LOOKING STATEMENTS
This document includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical facts
included in this document, including statements regarding production targets,
anticipated production rates, planned capital expenditures, the availability of
capital resources to fund capital expenditures, estimates of proved reserves,
wells planned to be drilled in the future, the Company's financial position,
business strategy and other plans and objectives for future operations, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, such statements are
based upon assumptions and anticipated results that are subject to numerous
uncertainties. Actual results may vary significantly from those anticipated due
to many factors, including drilling results, oil and gas prices, industry
conditions, the prices of goods and services, the availability of drilling rigs
and other support services and the availability of capital resources. In
addition, the drilling of oil and gas wells and the production of hydrocarbons
are subject to governmental regulations and operating risks. 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 such
factors.
ITEM 2. PROPERTIES
Substantially all of the Company's proved properties are located in the
federal waters of the Gulf of Mexico. The more significant proved producing
properties stretch from the West Delta area offshore Louisiana, south-southeast
of New Orleans, to the High Island area offshore Texas, south-southeast of
Houston. These properties lie in water depths that range from 45 feet to 480
feet. For 1998, no single field accounted for more that 10% of the Company's net
production. As of December 31, 1998, the Company owns interests in 133 leases
and operates 121 platforms, 70 of which are considered major platforms. Major
platforms are those that have six or more wells or two pieces of production
equipment.
-8-
<PAGE> 11
The Company's 10 largest properties accounted for approximately 52% of
the Company's equivalent proved reserves at December 31, 1998, but no single
property held more that 11% of the Company's equivalent proved reserves as of
such date, nor did any single property hold more that 15% of the net present
value of proved reserves as of such date.
The Company owns interests in four proved producing properties onshore
south Louisiana. The Company also owns unproved acreage in and adjacent to
these producing properties and in other coastal parishes in Louisiana.
Additionally, the Company owns unproved acreage in the Gulf Coast region of
Texas.
OIL AND GAS RESERVES
The following table sets forth estimated net proved oil and gas
reserves of the Company (all within the United States) and the present value of
estimated future pre-tax net cash flows related to such reserves as of December
31, 1998. Unless otherwise noted, all information in this Form 10-K relating to
oil and gas reserves and the estimated future net cash flows attributable
thereto are based upon estimates prepared by the Company and are net to the
Company's interest. The present value of estimated future pre-tax net cash flows
was prepared using constant prices as of December 31, 1998, discounted at 10%
per annum.
<TABLE>
<CAPTION>
PROVED RESERVES
--------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ---------
<S> <C> <C> <C>
Oil and condensate (MBbls)................................. 14,648 523 15,171
Gas (MMcf)................................................. 388,040 34,237 422,277
Total proved reserves (MMcfe).............................. 475,927 37,377 513,304
Present value of estimated future pre-tax net
cash flows (in thousands)............................... $ 528,871 $ 20,947 $ 549,818
</TABLE>
Ryder Scott Company, Petroleum Engineers ("Ryder Scott"), has prepared
estimates of the Company's proved reserves and future pre-tax net cash flows
therefrom as of December 31, 1994, 1995, 1996, 1997 and 1998. Ryder Scott's
estimates of equivalent proved reserves were 106.0%, 100.5%, 96.3%, 102.4% and
99.2%, respectively, of the Company's estimates of proved reserves for the same
periods. Ryder Scott's estimates of the present value of future pre-tax net cash
flows attributable to the Company's proved reserves were 107.9%, 102.4%, 93.7%,
96.5% and 99.9%, respectively, of the Company's estimates for the same periods.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and the
timing of development expenditures, including many factors beyond the control of
the producer. The reserve data set forth herein represents estimates only.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates made by different engineers often vary from one another. In addition,
results of drilling, testing, and production subsequent to the date of an
estimate may justify revisions of such estimates, and such revisions may be
material. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately recovered. Furthermore, the
estimated future net revenues from proved reserves and the present value thereof
are based upon certain assumptions, including future prices, production levels
and costs, that may not prove correct.
As is generally the case in the Gulf of Mexico, the Company's producing
properties are characterized by a high initial production rate, followed by a
steep decline in production. As a result, the Company must locate and develop or
acquire new oil and gas reserves to replace those being depleted by production.
Without successful exploration or acquisition activities, the Company's reserves
and revenues will decline rapidly.
As an operator of domestic oil and gas properties, the Company has
filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves,"
as required by Public Law 93-275. There are differences between the reserves as
reported on Form EIA-23 and as reported herein. The differences are attributable
to the fact that Form EIA-23 requires that an operator report on the total
reserves attributable to wells that are operated by it, without regard to
ownership (i.e., reserves are reported on a gross operated basis, rather than on
a net interest basis).
-9-
<PAGE> 12
FINDING COSTS
The following table sets forth certain information regarding the costs
associated with finding, acquiring and developing the Company's domestic proved
oil and gas reserves:
<TABLE>
<CAPTION>
CAPITALIZED RESERVES COST TO
COSTS(1) ADDED FIND AND DEVELOP
(IN THOUSANDS) (MMcfe) (PER Mcfe)
-------------- -------- ----------------
<S> <C> <C> <C>
1994................................................... $ 116,476 97,513 $1.19
1995 .................................................. 103,511 102,580 1.01
1996................................................... 162,315 119,050 1.36
1997................................................... 237,574 190,279 1.25
1998................................................... 304,891 166,472 1.83
--------- --------
Five-year period ended December 31, 1998.......... $ 924,767 675,894 $1.37
========= ========
</TABLE>
(1) Capitalized costs represent only domestic capitalized expenditures of the
Company as shown in the following table under the caption "--Development,
Exploration and Acquisition Capital Expenditures," excluding interest
capitalized.
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the
capitalized costs incurred in the purchase of proved and unproved properties and
in development and exploration activities:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Property acquisition:
Unproved properties - Domestic ........................... $ 3,400 $ 31,541 $ 5,670 $ 10,154 $ 2,020
Unproved properties - International ...................... -- 7,196 -- -- --
Proved properties - Domestic ............................. 86,219 30,368 28,480 29,393 32,810
Exploration - Domestic ..................................... 60,087 59,787 48,525 32,518 17,710
Exploration - International ................................ 1,512 4,908 -- -- --
Development - Domestic ..................................... 155,185 115,878 79,640 31,446 63,936
Interest capitalized - Domestic ............................ 4,369 3,481 1,508 674 217
-------- -------- -------- -------- --------
Total capitalized costs .................................. $310,772 $253,159 $163,823 $104,185 $116,693
======== ======== ======== ======== ========
</TABLE>
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for
each year of the three-year period ended December 31, 1998:
<TABLE>
<CAPTION>
1998 1997 1996
------------------ ---------------- ---------------
GROSS NET GROSS NET GROSS NET
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Productive - Domestic ..................................... 16 4.4 9 6.1 8 4.5
Nonproductive - Domestic .................................. 8 5.8 9 6.2 7 3.4
Nonproductive - International ............................. -- -- 1 0.3 -- --
------ ------ ------ ------ ------ ------
Total ................................................ 24 10.2 19 12.6 15 7.9
====== ====== ====== ====== ====== ======
Development wells:
Productive - Domestic ..................................... 17 11.4 18 9.4 24 10.1
Nonproductive - Domestic .................................. 0.9 1 0.5 1 0.3
------ ------ ------ ------ ------ ------
Total ................................................ 19 12.3 19 9.9 25 10.4
====== ====== ====== ====== ====== ======
</TABLE>
The Company was in the process of drilling 2 gross (1.0 net) exploratory
and 2 gross (0.7 net) development wells at December 31, 1998.
-10-
<PAGE> 13
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and gas
wells (all within the United States) in which the Company owned an interest as
of December 31, 1998:
<TABLE>
<CAPTION>
COMPANY OUTSIDE TOTAL
OPERATED OPERATED PRODUCTIVE
COMPANY WELLS WELLS WELLS
OPERATED ------------- ------------- -------------
PLATFORMS GROSS NET GROSS NET GROSS NET
--------- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C>
Offshore Louisiana
Federal:
Oil.............................. 28 65 37.9 -- -- 65 37.9
Gas.............................. 80 112 67.2 36 7.0 148 74.2
State:
Oil.............................. 1 1 0.8 -- -- 1 0.8
Gas.............................. 2 1 0.7 -- -- 1 0.7
Onshore Louisiana
Oil.............................. -- 5 1.9 -- -- 5 1.9
Gas.............................. -- 3 1.8 4 1.0 7 2.8
Offshore Texas
Federal:
Oil.............................. 1 3 1.6 -- -- 3 1.6
Gas.............................. 9 17 10.2 -- -- 17 10.2
--- --- ----- --- ----- --- -----
Total.......................... 121 207 122.1 40 8.0 247 130.1
=== === ===== ==== ===== === =====
</TABLE>
ACREAGE DATA
The following table sets forth certain information regarding the
Company's developed and undeveloped lease acreage as of December 31, 1998:
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
------------------- -------------------
GROSS NET GROSS NET
------- ------- ------- -------
<S> <C> <C> <C> <C>
Offshore Louisiana:
Federal waters .................... 386,074 222,136 81,975 53,456
State waters ...................... 3,153 2,339 866 866
Onshore Louisiana .................... 10,729 5,563 24,604 12,548
Offshore Texas:
Federal waters .................... 35,820 21,705 57,600 42,768
State waters ...................... -- -- -- --
Onshore Texas ........................ -- -- 2,881 720
Offshore People's Republic of China .. -- -- 415,000 145,250
------- ------- ------- -------
Total .......................... 435,776 251,743 582,926 255,608
======= ======= ======= =======
</TABLE>
Leases covering approximately 26,520 (17,133 net to the Company),
37,453 (27,570 net to the Company), 23,098 (17,269 net to the Company), 35,465
(26,335 net to the Company) and 10,760 (7,880 net to the Company) undeveloped
acres are scheduled to expire in 1999, 2000, 2001, 2002 and 2003, respectively.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty interests,
liens incident to operating agreements, liens for current taxes and other
burdens that the Company believes do not materially interfere with the use of or
affect the value of such properties. The MMS must approve all transfers of
record title or
-11-
<PAGE> 14
operating rights on leases on the OCS. The MMS approval process can in some
cases delay the requested transfer for a significant period of time.
OIL AND GAS TERMS
The definitions set forth below shall apply to the indicated terms as
used in this document. All volumes of natural gas referred to herein are stated
at the legal pressure base of the state or area where the reserves exist and at
60 degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
Basis Risk. The risk associated with the sales point price for oil or
gas production varying from the reference (or settlement) price for a particular
hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production
of oil or natural gas, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Developed acreage. The number of acres that are allocated or assignable
to producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry hole or well. A well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Farm-in or farm-out. An agreement whereunder the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in,"
while the interest transferred by the assignor is a "farm-out."
Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Finding costs. Costs associated with acquiring and developing proved
oil and gas reserves which are capitalized by the Company pursuant to generally
accepted accounting principles.
Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.
Liquids. Crude oil, condensate and natural gas liquids.
-12-
<PAGE> 15
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons
per day.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
MMS. Mineral Management Service of the United States Department of the
Interior.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMbtu. One million Btus.
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
Net acres or net wells. The sum of the fractional working interests
owned in gross acres or gross wells, as the case may be.
NYMEX. New York Merchantile Exchange.
Present value. When used with respect to oil and natural gas reserves,
the estimated value of future gross revenues (estimated in accordance with the
requirements of the Securities and Exchange Commission) to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date indicated,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expenses or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
-13-
<PAGE> 16
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property
entitling the owner to a share of oil or natural gas production free of costs of
production.
Turnkey drilling contract. A fixed rate contract pursuant to which the
drilling contractor generally bears the risk of loss for unbudgeted
contingencies.
Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains
proved reserves.
Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and a share
of production.
Workover. Operations on a producing well to restore or increase
production.
-14-
<PAGE> 17
ITEM 3. LEGAL PROCEEDINGS
The Company has been named as a defendant in certain lawsuits arising
in the ordinary course of business. While the outcome of these lawsuits cannot
be predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows or results of
operations of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names and ages
(as of February 28, 1999) of and positions held by each of the Company's
executive officers. The Company's executive officers serve at the discretion of
the Board of Directors.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Joe B. Foster............................ 64 Chairman of the Board, President and Chief Executive Officer
Robert W. Waldrup........................ 54 Vice President - Operations and Director
David A. Trice........................... 50 Vice President - Finance and International
Terry W. Rathert......................... 46 Vice President - Planning and Administration and Secretary
David F. Schaible........................ 38 Vice President - Acquisitions and Development
William D. Schneider..................... 47 Vice President - International Exploration
Elliott Pew.............................. 44 Vice President - Exploration
Ronald P. Lege........................... 54 Controller and Assistant Secretary
C. William Austin........................ 46 Legal Counsel and Assistant Secretary
James P. Ulm, II......................... 36 Treasurer
</TABLE>
Each of the executive officers has held the position set forth opposite
his name for the past five years except as follows:
David A. Trice has served as Vice President - Finance and International
since July 1997. Prior to joining the Company, he served as President, Chief
Executive Officer and Director of Huffco Group, Inc.
Terry W. Rathert has served as Vice President - Planning and
Administration and Secretary since July 1997. From 1992 to July 1997, he served
as Vice President, Chief Financial Officer and Secretary of the Company.
David F. Schaible has served as Vice President - Acquisitions &
Development since February 1995. From 1992 to 1995, he served as
Manager-Acquisitions & Development of the Company.
William D. Schneider has served as Vice President - International
Exploration since January 1998. From 1992 to January 1998 , he served as
Manager-Exploration of the Company.
Elliott Pew has served as Vice President - Exploration since January
1998. Prior to joining the Company, he served as Senior Vice President of Louis
Dreyfus Natural Gas Company's Gulf Coast Region and prior to Louis Dreyfus'
merger with American Exploration Company in October 1997, as Senior Vice
President of Exploration for American Exploration Company from March 1997 to the
date of such merger. From 1992 to March 1997, Mr. Pew was Vice President of
Exploration for American Exploration Company.
C. William Austin has served as Legal Counsel and Assistant Secretary
since March 1994. From 1989 to March 1994, Mr. Austin was employed as a staff
attorney for Energy Service Company, Inc., an international contract drilling
and marine service company headquartered in Dallas, Texas.
James P. Ulm, II has served as Treasurer of the Company since June
1995. From 1989 to June 1995, Mr. Ulm was employed in managerial positions, most
recently as Treasurer, by American Exploration Company.
-15-
<PAGE> 18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock of the Company is listed on the New York Stock
Exchange under the symbol "NFX." The following table sets forth, for the periods
indicated, the range of the high and low sales prices of the Common Stock as
reported by the New York Stock Exchange during the periods shown.
<TABLE>
<CAPTION>
HIGH LOW
------- -------
<S> <C> <C>
1997
First Quarter..................................................................... 28 18 1/2
Second Quarter ................................................................... 23 7/8 16 7/8
Third Quarter..................................................................... 28 1/8 19 15/16
Fourth Quarter.................................................................... 33 20
1998
First Quarter..................................................................... 27 11/16 19 9/16
Second Quarter.................................................................... 26 3/8 17 13/16
Third Quarter..................................................................... 24 7/8 15 7/16
Fourth Quarter ................................................................... 26 7/16 16 5/8
1999
First Quarter (through February 28, 1999) ........................................ 22 3/16 14 7/8
</TABLE>
On February 26, 1999 the last reported sale price of the Common Stock
on the New York Stock Exchange Composite Tape was $ 16 1/4 per share.
As of February 26, 1999 there were approximately 323 holders of record
of the Common Stock of the Company.
The Company has not paid any cash dividends in the past and does not
intend to pay cash dividends on its Common Stock in the foreseeable future. The
Company currently intends to retain any earnings for the future operation and
development of its business. Any future cash dividends to holders of Common
Stock would depend on future earnings, capital requirements, the Company's
financial condition and other factors deemed relevant by the Board of Directors.
In addition, the payment of dividends is restricted by the terms of the
Company's credit facility. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Item 8. Financial Statements
and Supplementary Data."
ITEM 6. SELECTED FINANCIAL DATA
For information concerning this item, see page 18 of the Newfield
Exploration Company Annual Report to Stockholders for the year ended December
31, 1998 (the "Annual Report") as filed with the Securities and Exchange
Commission as Exhibit 13.1 to this Form 10-K, which information is incorporated
herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
For information concerning this item, see pages 19 through 27 of the
Annual Report, which information is incorporated herein by reference.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from adverse changes in oil and
gas prices and interest rates, as discussed below.
Oil and Gas Prices. As an independent oil and gas producer, the
Company's revenue, profitability, access to capital and future rate of growth
are substantially dependent upon the prevailing prices of natural gas, oil and
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<PAGE> 19
condensate. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond the control of the Company. From time to
time, the Company has utilized and expects to continue to utilize hedging
transactions with respect to a portion of its oil and gas production to achieve
a more predictable cash flow, as well as to reduce its exposure to price
fluctuations. While hedging limits the downside risk of adverse price movements,
it may also limit future revenues from favorable price movements. Because gains
or losses associated with hedging transactions are included in oil and gas
revenues when the hedged production is delivered, such gains and losses are
generally offset by similar changes in the realized prices of the commodities.
See "Item 1. Business - Volatility of Oil and Gas Prices and Hedging" in this
Form 10-K and "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Hedging" in the Annual Report, which information is
incorporated herein by reference, for a more detailed discussion of oil and gas
price volatility, the Company's hedging practices and the risks associated with
such volatility and hedging practices and for a table that sets forth the
Company's open hedge position at December 31, 1998 and other related
information.
Interest Rates. At December 31, 1998, the Company had approximately
$209 million of outstanding long-term debt. A portion of such debt (the
Company's 7.45% senior unsecured notes, due 2007) is subject to a fixed rate of
interest, and the remainder (which represents borrowings under the Credit
Facility) is subject to a rate of interest that fluctuates based on short-term
interest rates. The Company has no open interest rate hedge positions to reduce
its exposure to changes in interest rates. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources" in the Annual Report, which information is incorporated
herein by reference, for a more detailed discussion of the Company's exposure to
changes in interest rates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For information concerning this item, see pages 28 through 51 of the
Annual Report, which information is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
-17-
<PAGE> 20
PART III
For information concerning Item 10 - Directors and Executive Officers
of the Registrant, Item 11 - Executive Compensation, Item 12 - Security
Ownership of Certain Beneficial Owners and Management and Item 13 - Certain
Relationships and Related Transactions, see the definitive Proxy Statement of
Newfield Exploration Company for the Annual Meeting of Stockholders to be held
on May 5, 1999 which will be filed with the Securities and Exchange Commission
and is incorporated herein by reference, and "Part I - Item 4A. Executive
Officers of the Registrant."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following financial statements of the Company and the report of
management and the Company's independent accountants thereon are included on
pages 28 through 51 of the Annual Report, and are incorporated herein by
reference:
Management Report on Financial Statements
Report of Independent Accountants
Consolidated Balance Sheet as of the fiscal years ended December 31,
1998 and 1997
Consolidated Statement of Income for each of the three years in the
period ended December 31, 1998
Consolidated Statement of Stockholders' Equity for each of the three
years in the period ended December 31, 1998
Consolidated Statement of Cash Flows for each of the three years in the
period ended December 31, 1998
Notes to the Consolidated Financial Statements
2. EXHIBITS
3.1 - Second Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
3.2 - Certificate of Amendment to Second Restated Certificate of
Incorporation of the Company dated May 15, 1997
(incorporated by reference to Exhibit 3.1.1 to the
Company's Registration Statement on Form S-3 (Registration
No. 333-32582)).
3.3 - Restated Bylaws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1994).
3.4 - Rights Agreement, dated as of February 12, 1999, between
the Company and ChaseMellon Shareholder Services L.L.C., as
Rights Agent, specifying the terms of the Rights to
Purchase Series A Junior Participating Preferred Stock, par
value $.01 per share, of the Company (incorporated by
reference to Exhibit 1 to the Company's Registration
Statement on Form 8-A filed with the Securities and
Exchange Commission on February 18, 1999).
*3.5 - Certificate of Designation of Series A Junior
Participating Preferred Stock, par value $.01 per share,
setting forth the terms of the Series A Junior
Participating Preferred Stock, par value $.01 per share.
-18-
<PAGE> 21
3.6 - Indenture dated as of October 15, 1997 among the Company,
as issuer, and First Union National Bank, as trustee
(incorporated by reference to Exhibit 4.3 to the Company's
Registration Statement on Form S-4 (Registration No.
333-39563)).
+10.1 - Newfield Exploration Company 1989 Stock Option Plan
(incorporated by reference to Exhibit 10.1 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.2 - Newfield Exploration Company 1990 Stock Option Plan
(incorporated by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.3 - Newfield Exploration Company 1991 Stock Option Plan
(incorporated by reference to Exhibit 10.3 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.4 - Newfield Exploration Company 1993 Stock Option Plan
(incorporated by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.5 - Newfield Employee 1993 Incentive Compensation Plan
(incorporated by reference to Exhibit 10.5 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.6 - Restricted Stock Plan and Agreement (incorporated by
reference to Exhibit 10.6 to the Company's Registration
Statement on Form S-1 (Registration No. 33-69540)).
10.7 - Amended and Restated Securityholders Agreement among
Newfield Exploration Company and certain of its
stockholders dated as of October 18, 1993 (incorporated by
reference to Exhibit 10.7 to the Company's Registration
Statement on Form S-1 (Registration No. 33-69540)).
+10.8 - Newfield Exploration Company 1995 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-8 (Registration No.
33-92182)).
10.9 - Amended and Restated Credit Agreement dated as of October
9, 1997 among Newfield Exploration Company as the Company,
and The Chase Manhattan Bank as Agent, and the Banks
signatory hereto (without Exhibits) (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report
on Form 10-Q for the quarterly period ended September 31,
1997).
+10.10 - First Amendment to Amended and Restated Credit Agreement
dated as of August 20, 1998 among Newfield Exploration
Company as the Company, and The Chase Manhattan Bank as
Agent, and the Banks Signatory thereto (without Exhibits)
(incorporated by reference to Exhibit 10.1 to the Company's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on August 28, 1998).
+10.11 - Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (Restated) (incorporated by reference
to Exhibit 10.10 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.12 - Newfield Exploration Company Deferred Compensation Plan
(incorporated by reference to Exhibit 10.11 to the
Company's Registration Statement on Form S-3 (Registration
No. 333-32587)).
+10.13 - Subscription Agreement between the Company and Terry
Huffington dated May 15, 1997 (incorporated by reference to
Exhibit 10.12 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.14 - Subscription Agreement between the Company and David A.
Trice dated May 15, 1997 (incorporated by reference to
Exhibit 10.13 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
-19-
<PAGE> 22
+10.15 - Asset Purchase Agreement among Newfield Offshore Inc.,
Huffco and Huffco Turkey, Inc. dated as of May 12, 1997
(without exhibits and schedules) (incorporated by reference
to Exhibit 10.14 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.16 - Resolution of Members Establishing the Preferences,
Limitations and Relative Rights of Series "A" Preferred
Shares of Huffco China, LDC dated May 14, 1997
(incorporated by reference to Exhibit 10.15 to the
Company's Registration Statement on Form S-3 (Registration
No. 333- 32587)).
+10.17 - Guaranty Agreement among the Company, Newfield Offshore
Inc., Huffco and Huffco Turkey, Inc. dated as of May 15,
1997 (incorporated by reference to Exhibit 10.16 to the
Company's Registration Statement on Form S-3 (Registration
No. 333-32587)).
10.18 - Promissory Note dated July 15, 1997 by the Company as maker
in favor of The Chase Manhattan Bank (incorporated by
reference to Exhibit 10.17 to the Company's Registration
Statement on Form S-3 (Registration No. 333-32587)).
+10.19 - Newfield Exploration Company 1998 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1.1 to the
Company's Registration Statement on Form S-8 (Registration
No. 333-59383)).
+10.20 - Amendment of 1998 Omnibus Stock Plan, dated May 7, 1998
(incorporated by reference to Exhibit 4.1.2 to the
Company's Registration Statement on Form S-8 (Registration
No. 333-59383)).
*13.1 - Newfield Exploration Company Annual Report to Stockholders
for the year ended December 31, 1998.
21.1 - The Registrant has no subsidiaries other than subsidiaries
that, considered in the aggregate as a single subsidiary,
do not constitute a significant subsidiary.
*23.1 - Consent of PricewaterhouseCoopers LLP.
*23.2 - Consent of Ryder Scott Company.
*27.1 - Financial Data Schedule (included only in the electronic
filing of this document).
------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
(b) REPORTS ON FORM 8-K
None
-20-
<PAGE> 23
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, in the City of
Houston, State of Texas, on the 1st day of March, 1999.
NEWFIELD EXPLORATION COMPANY
By: /s/ Joe B. Foster
----------------------------
Joe B. Foster
Chairman of the Board and Chief
Executive Officer
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the registrant in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Joe B. Foster Chairman of the Board and March 1, 1999
- ----------------------------- Chief Executive Officer
Joe B. Foster (Principal Executive Officer)
/s/ Robert W. Waldrup Vice President - Operations March 1, 1999
- ----------------------------- and Director
Robert W. Waldrup
/s/ Terry W. Rathert Vice President - Planning and March 1, 1999
- ----------------------------- Administration and Secretary
Terry W. Rathert (Principal Financial Officer)
/s/ Ronald P. Lege Controller and Assistant Secretary March 1, 1999
- ----------------------------- (Principal Accounting Officer)
Ronald P. Lege
/s/ Philip J. Burguieres Director March 1, 1999
- -----------------------------
Philip J. Burguieres
/s/ Charles W. Duncan, Jr. Director March 1, 1999
- -----------------------------
Charles W. Duncan, Jr.
/s/ Dennis Hendrix Director March 1, 1999
- -----------------------------
Dennis Hendrix
/s/ Terry Huffington Director March 1, 1999
- -----------------------------
Terry Huffington
/s/ Howard H. Newman Director March 1, 1999
- -----------------------------
Howard H. Newman
/s/ Thomas G. Ricks Director March 1, 1999
- -----------------------------
Thomas G. Ricks
/s/ John C. Sawhill Director March 1, 1999
- -----------------------------
John C. Sawhill
/s/ C. E. Shultz Director March 1, 1999
- -----------------------------
C.E. Shultz
</TABLE>
-21-
<PAGE> 24
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <C> <C>
3.1 - Second Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
3.2 - Certificate of Amendment to Second Restated Certificate of
Incorporation of the Company dated May 15, 1997
(incorporated by reference to Exhibit 3.1.1 to the
Company's Registration Statement on Form S-3 (Registration
No. 333-32582)).
3.3 - Restated Bylaws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1994).
3.4 - Rights Agreement, dated as of February 12, 1999, between
the Company and ChaseMellon Shareholder Services L.L.C., as
Rights Agent, specifying the terms of the Rights to
Purchase Series A Junior Participating Preferred Stock, par
value $.01 per share, of the Company (incorporated by
reference to Exhibit 1 to the Company's Registration
Statement on Form 8-A filed with the Securities and
Exchange Commission on February 18, 1999).
*3.5 - Certificate of Designation of Series A Junior
Participating Preferred Stock, par value $.01 per share,
setting forth the terms of the Junior Participating
Preferred Stock, par value $.01 per share.
3.6 - Indenture dated as of October 15, 1997 among the Company,
as issuer, and First Union National Bank, as trustee
(incorporated by reference to Exhibit 4.3 to the Company's
Registration Statement on Form S-4 (Registration No.
333-39563)).
+10.1 - Newfield Exploration Company 1989 Stock Option Plan
(incorporated by reference to Exhibit 10.1 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.2 - Newfield Exploration Company 1990 Stock Option Plan
(incorporated by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.3 - Newfield Exploration Company 1991 Stock Option Plan
(incorporated by reference to Exhibit 10.3 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.4 - Newfield Exploration Company 1993 Stock Option Plan
(incorporated by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.5 - Newfield Employee 1993 Incentive Compensation Plan
(incorporated by reference to Exhibit 10.5 to the Company's
Registration Statement on Form S-1 (Registration No.
33-69540)).
+10.6 - Restricted Stock Plan and Agreement (incorporated by
reference to Exhibit 10.6 to the Company's Registration
Statement on Form S-1 (Registration No. 33-69540)).
10.7 - Amended and Restated Securityholders Agreement among
Newfield Exploration Company and certain of its
stockholders dated as of October 18, 1993 (incorporated by
reference to Exhibit 10.7 to the Company's Registration
Statement on Form S-1 (Registration No. 33-69540)).
+10.8 - Newfield Exploration Company 1995 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-8 (Registration No.
33-92182)).
10.9 - Amended and Restated Credit Agreement dated as of October
9, 1997 among Newfield Exploration Company as the Company,
and The Chase Manhattan Bank as Agent, and the Banks
signatory hereto (without Exhibits) (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report
on Form 10-Q for the quarterly period ended September 31,
1997).
+10.10 - First Amendment to Amended and Restated Credit Agreement
dated as of August 20, 1998 among Newfield Exploration
Company as the Company, and The Chase Manhattan Bank as
Agent, and the Banks Signatory thereto (without Exhibits)
(incorporated by reference to Exhibit 10.1 to the Company's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on August 28, 1998).
+10.11 - Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (Restated) (incorporated by reference
to Exhibit 10.10 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.12 - Newfield Exploration Company Deferred Compensation Plan
(incorporated by reference to Exhibit 10.11 to the
Company's Registration Statement on Form S-3 (Registration
No. 333-32587)).
+10.13 - Subscription Agreement between the Company and Terry
Huffington dated May 15, 1997 (incorporated by reference to
Exhibit 10.12 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.14 - Subscription Agreement between the Company and David A.
Trice dated May 15, 1997 (incorporated by reference to
Exhibit 10.13 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.15 - Asset Purchase Agreement among Newfield Offshore Inc.,
Huffco and Huffco Turkey, Inc. dated as of May 12, 1997
(without exhibits and schedules) (incorporated by reference
to Exhibit 10.14 to the Company's Registration Statement on
Form S-3 (Registration No. 333-32587)).
+10.16 - Resolution of Members Establishing the Preferences,
Limitations and Relative Rights of Series "A" Preferred
Shares of Huffco China, LDC dated May 14, 1997
(incorporated by reference to Exhibit 10.15 to the
Company's Registration Statement on Form S-3 (Registration
No. 333- 32587)).
+10.17 - Guaranty Agreement among the Company, Newfield Offshore
Inc., Huffco and Huffco Turkey, Inc. dated as of May 15,
1997 (incorporated by reference to Exhibit 10.16 to the
Company's Registration Statement on Form S-3 (Registration
No. 333-32587)).
10.18 - Promissory Note dated July 15, 1997 by the Company as maker
in favor of The Chase Manhattan Bank (incorporated by
reference to Exhibit 10.17 to the Company's Registration
Statement on Form S-3 (Registration No. 333-32587)).
+10.19.1 - Newfield Exploration Company 1998 Omnibus Stock Plan
incorporated by reference to Exhibit 4.1.1 to the Company's
Registration Statement on Form S-8 (Registration No.
333-59383)).
+10.19.2 - Amendment of 1998 Omnibus Stock Plan, dated May 7, 1998
(incorporated by reference to Exhibit 4.1.2 to the
Company's Registration Statement on Form S-8 (Registration
No. 333-59383)).
*13.1 - Newfield Exploration Company Annual Report to Stockholders
for the year ended December 31, 1998.
21.1 - The Registrant has no subsidiaries other than subsidiaries
that, considered in the aggregate as a single subsidiary,
do not constitute a significant subsidiary.
*23.1 - Consent of PricewaterhouseCoopers LLP.
*23.2 - Consent of Ryder Scott Company.
*27.1 - Financial Data Schedule (included only in the electronic
filing of this document).
</TABLE>
------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
<PAGE> 1
EXHIBIT 3.5
CERTIFICATE OF DESIGNATION
OF
JUNIOR PARTICIPATING PREFERRED STOCK
OF
NEWFIELD EXPLORATION COMPANY
Pursuant to Section 151 of the
General Corporation Law
of the State of Delaware
Newfield Exploration Company (the "Corporation"), a corporation
organized and existing under the General Corporation Law of the State of
Delaware (the "DGCL"), hereby certifies that the following resolution was
adopted by the Board of Directors of the Corporation as required by Section 151
of the DGCL at a meeting duly called and held on February 12, 1999:
RESOLVED, that, pursuant to the authority granted to and vested in the
Board of Directors of the Corporation in accordance with the provisions of the
Corporation's Second Restated Certificate of Incorporation, as amended, and
Section 151 of the DGCL, the Board of Directors of the Corporation hereby
creates a series of preferred stock, par value $.01 per share, of the
Corporation and hereby states that the designation and number of shares and the
relative rights, preferences and limitations thereof (in addition to the
provisions set forth in the Second Restated Certificate of Incorporation of the
Corporation, as amended, that are applicable to preferred stock of all series)
are as follows:
Junior Participating Preferred Stock:
Section 1. Designation and Amount. The shares of such series shall be
designated as "Junior Participating Preferred Stock" (the "Junior Preferred
Stock") and the number of shares constituting the Junior Preferred Stock shall
be 100,000. Such number of shares may be increased or decreased by resolution of
the Board of Directors; provided, that no decrease shall reduce the number of
shares of Junior Preferred Stock to a number less than the number of shares then
outstanding plus the number of shares reserved for issuance upon the exercise of
outstanding options, rights or warrants or upon the conversion of any
outstanding securities issued by the Corporation convertible into Junior
Preferred Stock.
1
<PAGE> 2
Section 2. Dividends and Distributions.
(a) Subject to the rights of the holders of any shares of any
series of preferred stock (or any similar stock) ranking prior and
superior to the Junior Preferred Stock with respect to dividends, the
holders of shares of Junior Preferred Stock, in preference to the
holders of common stock, par value $0.01 per share ("Common Stock"), of
the Corporation, and of any other junior stock, shall be entitled to
receive, when, as and if declared by the Board of Directors out of
funds legally available for such purpose, quarterly dividends payable
on the first business day of February, May, August and November in each
year (each such date being referred to herein as a "Quarterly Dividend
Payment Date") as provided in paragraphs (b) and (c) of this Section 2
in an amount per share (rounded to the nearest cent) equal to the
greater of (i) $1.00 in cash and (ii) subject to the provision for
adjustment hereinafter set forth, 1,000 times the aggregate per share
amount (payable in cash) of all cash dividends, and 1,000 times the
aggregate per share amount (payable in kind) of all non-cash dividends
or other distributions, other than a dividend payable in shares of
Common Stock or a subdivision of the outstanding shares of Common Stock
(by reclassification or otherwise), declared on the Common Stock since
the immediately preceding Quarterly Dividend Payment Date or, with
respect to the first Quarterly Dividend Payment Date, since the first
issuance of any share or fraction of a share of Junior Preferred Stock.
If the Corporation shall at any time declare or pay any dividend on the
Common Stock payable in shares of Common Stock, or effect a subdivision
or combination or consolidation of the outstanding shares of Common
Stock (by reclassification or otherwise) into a greater or lesser
number of shares of Common Stock, then in each such case the amount to
which holders of shares of Junior Preferred Stock were entitled
immediately prior to such event under clause (ii) of the preceding
sentence shall be adjusted by multiplying such amount by a fraction,
the numerator of which is the number of shares of Common Stock
outstanding immediately after such event and the denominator of which
is the number of shares of Common Stock that were outstanding
immediately prior to such event.
(b) The Corporation shall declare a dividend or distribution
on the Junior Preferred Stock as provided in paragraph (a) of this
Section 2 immediately after it declares a dividend or distribution on
the Common Stock (other than a dividend payable in shares of Common
Stock); provided that, if no dividend or distribution shall have been
declared on the Common Stock during the period between any Quarterly
Dividend Payment Date and the next subsequent Quarterly Dividend
Payment Date, a dividend of $1.00 per share payable in cash on the
Junior Preferred Stock shall nevertheless accrue and be cumulative on
the outstanding shares of Junior Preferred Stock as provided in
paragraph (c) of this Section 2.
(c) Dividends shall begin to accrue and be cumulative on
outstanding shares of Junior Preferred Stock from the Quarterly
Dividend Payment Date next preceding the date of issue of such shares,
unless the date of issue of such shares is (i) on or prior to the
record date for the first Quarterly Dividend Payment Date or (ii) on a
Quarterly Dividend
2
<PAGE> 3
Payment Date, in either of which cases dividends on such shares shall
begin to accrue and be cumulative from the date of issue of such
shares. Accrued but unpaid dividends shall not bear interest.
Dividends paid on the shares of Junior Preferred Stock in an amount
less than the total amount of such dividends at the time accrued and
payable on such shares shall be allocated pro rata on a share-by-share
basis among all such shares at the time outstanding. The Board of
Directors may fix a record date for the determination of holders of
shares of Junior Preferred Stock entitled to receive payment of a
dividend or distribution declared thereon, which record date shall be
not more than 60 days prior to the date fixed for the payment thereof.
Section 3. Voting Rights. The holders of shares of Junior Preferred
Stock shall have the following voting rights:
(a) Subject to the provisions for adjustment hereinafter set
forth, each share of Junior Preferred Stock shall entitle the holder
thereof to 1,000 votes on all matters submitted to a vote of the
stockholders of the Corporation. If the Corporation shall at any time
declare or pay any dividend on Common Stock payable in shares of Common
Stock, or effect a subdivision or combination of the outstanding shares
of Common Stock (by reclassification or otherwise) into a greater or
lesser number of shares of Common Stock, then in each such case the
number of votes per share to which holders of shares of Junior
Preferred Stock were entitled immediately prior to such event shall be
adjusted by multiplying such number by a fraction the numerator of
which is the number of shares of Common Stock outstanding immediately
after such event and the denominator of which is the number of shares
of Common Stock that were outstanding immediately prior to such event.
(b) Except as otherwise provided herein or in any other series
designation creating a series of preferred stock or any similar stock
or as otherwise provided by law, the holders of shares of Junior
Preferred Stock and the holders of shares of Common Stock and any other
capital stock of the Corporation having general voting rights shall
vote together as one class on all matters submitted to a vote of the
stockholders of the Corporation.
(c) Except as set forth herein or as otherwise provided by
law, holders of Junior Preferred Stock shall have no special voting
rights and their consent shall not be required (except to the extent
they are entitled to vote with holders of Common Stock as set forth
herein) for taking any corporate action.
Section 4. Certain Restrictions.
(a) Whenever quarterly dividends or other dividends or
distributions payable on the Junior Preferred Stock as provided in
Section 2 are in arrears, thereafter and until all accrued and unpaid
dividends and distributions, whether or not declared, on shares of
Junior Preferred Stock outstanding shall have been paid in full, or
declared and a sum
3
<PAGE> 4
sufficient for the payment therefor be set apart for payment and be in
the process of payment, the Corporation shall not:
(i) declare or pay dividends, or make any other
distributions, on any shares of stock ranking junior (either
as to dividends or upon liquidation, dissolution or winding
up) to the Junior Preferred Stock;
(ii) declare or pay dividends, or make any other
distributions, on any shares of stock ranking on a parity
(either as to dividends or upon liquidation, dissolution or
winding up) with the Junior Preferred Stock, except dividends
paid ratably on the Junior Preferred Stock and all such parity
stock on which dividends are payable or in arrears in
proportion to the total amounts to which the holders of all
such shares are then entitled;
(iii) redeem or purchase or otherwise acquire for
consideration shares of any stock ranking junior (either as to
dividends or upon liquidation, dissolution or winding up) to
the Junior Preferred Stock; provided that the Corporation may
at any time redeem, purchase or otherwise acquire shares of
any such junior stock in exchange for shares of any stock of
the Corporation ranking junior (as to both dividends and upon
dissolution, liquidation or winding up) to the Junior
Preferred Stock; or
(iv) redeem or purchase or otherwise acquire for
consideration any shares of Junior Preferred Stock or any
shares of stock ranking on a parity (either as to dividends or
upon liquidation, dissolution or winding up) with the Junior
Preferred Stock, except in accordance with a purchase offer
made in writing or by publication (as determined by the Board
of Directors) to all holders of such shares upon such terms as
the Board of Directors, after consideration of the respective
annual dividend rates and other relative rights and
preferences of the respective series and classes, shall
determine in good faith will result in fair and equitable
treatment among the holders of the respective series or
classes.
(b) The Corporation shall not permit any subsidiary of the
Corporation to purchase or otherwise acquire for consideration any
shares of stock of the Corporation unless the Corporation could, under
paragraph (a) of this Section 4, purchase or otherwise acquire such
shares at such time and in such manner.
Section 5. Reacquired Shares. Any shares of Junior Preferred Stock
purchased or otherwise acquired by the Corporation in any manner whatsoever
shall be retired and canceled promptly after the acquisition thereof. All such
shares shall upon their cancellation become authorized but unissued shares of
preferred stock and may be reissued as part of a new series of preferred stock
subject to the conditions and restrictions on issuance set forth herein, in the
Corporation's certificate of incorporation then in effect or in any other series
designation creating a series of preferred stock or any similar stock or as
otherwise required by law.
4
<PAGE> 5
Section 6. Liquidation, Dissolution or Winding Up. Upon any
liquidation, dissolution or winding up of the Corporation, no distribution shall
be made (a) to the holders of shares of stock ranking junior (either as to
dividends or as to amounts payable upon liquidation, dissolution or winding up)
to the Junior Preferred Stock unless, prior thereto, the holders of Junior
Preferred Stock shall have received an amount per share (rounded to the nearest
cent) equal to the greater of (i) $1,000 and (ii) subject to the provision for
adjustment hereinafter set forth, equal to 1,000 times the aggregate amount to
be distributed per share to holders of Common Stock, plus, in either case, an
amount equal to accrued and unpaid dividends and distributions thereon, whether
or not declared, to the date of such payment or (b) to the holders of stock
ranking on a parity (either as to dividends or as to amounts payable upon
liquidation, dissolution or winding up) with the Junior Preferred Stock, except
distributions made ratably on the Junior Preferred Stock and all such parity
stock in proportion to the total amounts to which the holders of all such shares
are entitled upon such liquidation, dissolution or winding up. If the
Corporation shall at any time declare or pay any dividend on Common Stock
payable in shares of Common Stock, or effect a subdivision or combination or
consolidation of the outstanding shares of Common Stock (by reclassification or
otherwise) into a greater or lesser number of shares of Common Stock, then in
each such case the aggregate amount to which holders of shares of Junior
Preferred Stock were entitled immediately prior to such event under the proviso
in clause (a)(ii) of the preceding sentence shall be adjusted by multiplying
such amount by a fraction the numerator of which is the number of shares of
Common Stock outstanding immediately after such event and the denominator of
which is the number of shares of Common Stock that were outstanding immediately
prior to such event.
Section 7. Consolidation, Merger, etc. If the Corporation shall enter
into any consolidation, merger, combination or other transaction in which shares
of Common Stock are exchanged for or changed into other stock or securities,
cash or any other property, or any combination thereof, then in any such case
each share of Junior Preferred Stock shall at the same time be similarly
exchanged or changed into an amount per share, subject to the provision for
adjustment hereinafter set forth, equal to 1,000 times the aggregate amount of
stock, securities, cash or any other property (payable in kind), or any
combination thereof, as the case may be, into which or for which each share of
Common Stock is changed or exchanged. If the Corporation shall at any time
declare or pay any dividend on the Common Stock payable in shares of Common
Stock, or effect a subdivision or combination or consolidation of the
outstanding shares of Common Stock (by reclassification or otherwise) into a
greater or lesser number of shares of Common Stock, then in each such case the
amount set forth in the preceding sentence with respect to the exchange or
change of shares of Junior Preferred Stock shall be adjusted by multiplying such
amount by a fraction, the numerator of which is the number of shares of Common
Stock outstanding immediately after such event and the denominator of which is
the number of shares of Common Stock that were outstanding immediately prior to
such event.
Section 8. Redemption. The shares of Junior Preferred Stock shall not
be redeemable. So long as any shares of Junior Preferred Stock remain
outstanding, the Corporation shall not purchase or otherwise acquire for
consideration any shares of stock ranking junior (either as to dividends or upon
liquidation, dissolution or winding up) to the Junior Preferred Stock unless the
5
<PAGE> 6
Corporation shall concurrently purchase or acquire for consideration a
proportionate number of shares of Junior Preferred Stock.
Section 9. Rank. The Junior Preferred Stock shall rank, with respect to
payment of dividends and the distribution of assets, junior to all series of any
other class of the Corporation's preferred stock.
Section 10. Amendment. At any time that any shares of Junior Preferred
Stock are outstanding, the certificate of incorporation of the Corporation shall
not be amended in any manner that would materially alter or change the powers,
preferences, privileges or special rights of the Junior Preferred Stock so as to
affect them adversely without the affirmative vote of the holders of a majority
of the outstanding shares of Junior Preferred Stock, voting together as a single
class.
IN WITNESS WHEREOF, this Certificate of Designations is executed on
behalf of the Corporation by its President, and attested by its Secretary, this
16th day of February, 1999.
NEWFIELD EXPLORATION COMPANY
By: /s/ JOE B. FOSTER
-------------------------------
Joe B. Foster
President
ATTEST:
/s/ TERRY W. RATHERT
- ----------------------------------
Terry W. Rathert
Secretary
6
<PAGE> 1
NEWFIELD
[NEWFIELD LOGO]
ANNUAL REPORT
10th
Anniversary
Edition
[1988-1998]
<PAGE> 2
OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1990 1993 1998
---- ---- ----
<S> <C> <C> <C>
ESTIMATED OIL AND GAS RESERVES
Net Proved Reserves:
Oil (MBbls) ....................... 939 6,414 15,171
Natural Gas (MMcf) ................ 17,428 102,261 422,277
Gas Equivalents (MMcfe) ........... 23,062 140,745 513,304
OIL AND GAS PRODUCTION
Oil (MBbls) ....................... 25 901 3,643
Natural Gas (MMcf) ................ 812 22,540 66,634
Gas Equivalents (MMcfe) ........... 964 27,946 88,494
Rank, Gulf of Mexico Operators .... 81 26 12
PROPERTY BASE
GULF OF MEXICO
Oil and Gas Leases ................ 20 63 133
Oil and Gas Platforms ............. 2 23 121
Rank, Gulf of Mexico Drilling ..... 38 18 8
Acreage Position (acres)
Developed (net) .............. 3,907 3,102 246,180
Undeveloped (net) ............ 36,635 23,925 97,090
3-D Seismic .................. 5,000 100,000 11,300,000
ONSHORE/INTERNATIONAL
Acreage Position (acres)
Developed (net) .............. -- -- 5,563
Undeveloped (net) ............ -- -- 158,518
3-D Seismic .................. -- -- 350,000
</TABLE>
<TABLE>
<CAPTION>
1990 1993 1998
---- ---- ----
<S> <C> <C> <C>
GROWTH IN PROVED RESERVES (Bcfe) 23 141 513
Last Five Years' CAGR: 29%
</TABLE>
<TABLE>
<CAPTION>
1990 1993 1998
---- ---- ----
<S> <C> <C> <C>
GROWTH IN PRODUCTION (Bcfe) 1 28 88.5
Last Five Years' CAGR: 26%
</TABLE>
1
<PAGE> 3
[PHOTOGRAPH OF HAND DEPICTED AS
DRAFTING FOUNDING BUSINESS PRINCIPLES]
FOUNDING BUSINESS PRINCIPLES
(Excerpted from Original Business Plan)
* "A new company composed of management and employees who have worked
together and established a superior track record in oil and gas
exploration/production"
* "Focus on an area of high potential"
* "A data intense, team oriented, technically strong exploration effort"
* "Operate with the economics, incentives and flexibility of an independent"
* "A selective acquisition effort...with definable reserve upsides"
* "A good mix of age and technical discipline...with equity compensation"
2
<PAGE> 4
10TH ANNIVERSARY EDITION REPORT TO STOCKHOLDERS
Dear Fellow Stockholder:
Those of you who follow the stock market know that 1998 was not a
good year for the oil and gas exploration and production sector. The median
stock price decline for the 47 companies in our universe was 48.5% for the
year, with 17 of the 47 declining more than 70%. Newfield's stock price was
down 10.5% for the year. Only three E&P companies in this universe had better
stock performance during 1998 than Newfield - Vastar, Anadarko and
gas-dominant Houston Exploration.
There was plenty of bad news during 1998 to prompt the dismal market
performance of the industry. Oil prices were down 33% compared to 1997. Natural
gas prices were down 19%. Further, the high drilling rig rates, high oil field
service costs and high levels of activity the industry experienced in the first
half of 1998 resulted in dramatically higher capital costs - due to reduced
efficiency as well as higher rates. Newfield's capital spending performance in
1998 was, like the rest of the industry's, disappointing. Capital expenditures
for the year totaled $311 million, and reserve additions were 167 Bcfe.
Approximately $66 million of the capital was used to develop reserves that were
booked in 1997.
This powerful combination of lower prices and higher costs led to
Newfield's income from operations being down from $41 million in 1997 to
$10.4 million in 1998. The lower prices existing at year end 1998 also led to
a $68 million "ceiling test" writedown at year end 1998. Under full cost
accounting requirements, we must, at the end of each quarter, recalculate the
net present value of our reserves, using the point-in-time prices existing at
the end of the quarter, even if higher longer term prices might be available
in financial markets. If the ceiling test calculation results in a lower
value than the book value of oil and gas properties, a writedown must be
taken. This was the case for Newfield at the end of the fourth quarter of
1998.
After the writedown, Newfield reported a net loss of $57.7 million,
or $1.55 per share (all per share amounts are on a diluted basis), versus net
income of $1.07 per share in 1997. Operating cash flow before working capital
changes was also down in 1998, from $162 million, or $4.26 per share, to $142
million, or $3.60 per share.
All of the bad news notwithstanding, there was plenty of good news for
Newfield in 1998.
First, our net production was up 20%, rising from 74 Bcfe (billion
cubic feet of natural gas equivalent) in 1997 to 88.5 Bcfe in 1998.
This continued our string of uninterrupted production growth since, as
a brand new company, we first began production in 1990.
[PICTURE OF NEWFIELD MANAGEMENT GROUP]
Secondly, Newfield's reserve base increased by 18% in 1998 to 513
Bcfe at year end, up from 435 Bcfe at year end 1997. This reserve growth was
the result of adding 167 Bcfe of new reserves during the year, which is 188%
of our 1998 production. That increase in reserves will lead to increased
production in 1999.
Thirdly, we conducted a successful hedging program adding $0.10 per
Mcfe to our average price realizations - or about $9.1 million of revenue.
Fourthly, we added 26 new leases in the Gulf of Mexico and continued t
o be a major operator there. Our current daily operated production in the
Gulf is about 590 million cubic feet of gas equivalent (MMcfe) per day, which
would rank us among the top ten operators. Our statistics indicate we were
the 8th most active driller in the Gulf during 1998.
Finally, our onshore Gulf Coast effort began to bear fruit as we
placed our Broussard discovery in Lafayette Parish, Louisiana, on
production. At full rate, this property will yield approximately 35 MMcfe per
day of operated production, of which 12 MMcfe per day is net to Newfield. In
addition, we initiated an exploration program in South Texas and are, as of
this date, drilling our first test there.
3
<PAGE> 5
On the financial front, we exited 1998 with a strong balance sheet and
superior credit statistics. In the very volatile market existing in September
1998 Newfield placed four million shares of equity resulting in net proceeds of
$83 million. To our knowledge, no other independent E&P company raised public
equity in the last half of 1998.
There is even some good news related to our 1998 capital spending
performance. Rig rates are now about 25-30% of what they were a year ago, other
oil field service costs are lower and every indication is that our cost to find
and develop will markedly improve in 1999.
Despite the current doldrums in our business, we are optimistic about
1999. Some reasons:
[GRAPH OF NEWFIELD PRODUCTION GROWTH BY YEAR]
* We see another year of 20% production growth. Our 1999 production
target from existing properties is 106 Bcfe.
* Only 17% of our 1999 production is expected to be in the form of
oil. The remainder is natural gas.
* Despite the current modest natural gas prices, many analysts foresee
a stronger second half for natural gas pricing. So do we.
* Favorable hedges are in place which will mitigate gas price risk in
the first half of 1999.
* We expect to reduce both operating costs and capital costs on a unit
basis.
* The financial stress, reduced budgets and consolidation now
occurring among E&P companies should increase available
opportunities.
We believe Newfield's strong balance sheet and access to capital, its
extensive data base and operating presence in the Gulf of Mexico, and its high
cash flow per unit of production make it well situated to take advantage of
opportunities during 1999. We are excited about the possibilities!
As you will note from the cover of this report, we are celebrating the
tenth anniversary of Newfield's founding. We have devoted a large part of this
report to looking back at where we have come from and speculating about where we
might go. I hope you don't find it too indulgent.
The accompanying chart illustrates the nature of building and growing
Newfield. Each color represents production from leases which first began
production in the noted year. While each year's group of new producing leases
may show some early growth as development takes place, inevitably natural
decline sets in. Newfield's production growth comes from the constant addition
of new producing leases. We must continuously generate new opportunities which
will result in the discovery or acquisition of new production and we must keep
going back to our existing leases seeking to forestall natural decline.
The chart also shows that some years are better than others in terms of
new production. Nonetheless, we have shown consistent overall growth. Newfield
is adapted to the "treadmill" nature of the Gulf of Mexico. We fully expect to
continue our pattern of year on year growth.
We are very proud of what we have accomplished in these ten short years.
Take a look at pages 13-14. These are the people that have made it happen. Allow
us to share our pride with you!
Sincerely,
/s/ JOE B. FOSTER
------------------
Joe B. Foster February 26, 1999
4
<PAGE> 6
10TH ANNIVERSARY MAJOR MILESTONES
[PHOTOGRAPH OF NEWFIELD'S FOUNDING EMPLOYEES]
1988/89
Newfield was founded in 1988 by Joe B. Foster. The Company was capitalized with
$9 million by an investment group led by Charles Duncan, the University of Texas
endowment funds and the founding employees (including those shown above).
1990
In May 1990, Newfield completed its first property acquisition with the purchase
of Eugene Island 172. Upon being designated as operator, Newfield initiated an
active workover program. By December 1990, daily production had increased from
0.2 MMcfe to over 20 MMcfe. Eugene Island 172 continues to produce at a rate of
approximately 4 MMcfe per day.
A second private placement in April 1990 added $37 million to Newfield's
capital. New stockholders in this private placement included Yale University,
Duke University, Dartmouth College and Warburg, Pincus Investors, L.P., which
became Newfield's largest stockholder.
[PHOTOGRAPH OF NEWFIELD EMPLOYEES
AT WORK USING GEOPHYSICAL WORKSTATION]
1991
Shown above is a picture of Newfield employees at work at the opportunity
generation process. Multi-disciplinary teams use workstations to analyze 3-D
seismic on fields like Ship Shoal 157, the Company's first operated exploratory
discovery. A six well drilling program was initiated in late 1990 and production
reached peak rates of 4,500 barrels of oil equivalent per day. Ship Shoal 157 is
still producing today with cumulative gross production of 7.5 MMBOE.
[PHOTOGRAPH OF EUGENE ISLAND 182 PLATFORM,
OFFSHORE IN THE GULF OF MEXICO]
1992
The purchase of proved reserves with drilling upside is an important part of
Newfield's business strategy. The acquisition of Eugene Island 181/182 (shown
above) resulted in a successful seven well drilling program. Following the
second phase of development, Eugene Island 181/182 was producing at a daily rate
of over 65 MMcfe. Drilling activities are planned in this field during 1999.
[PHOTOGRAPH OF NEWFIELD STOCK CERTIFICATE AND
CERTIFICATION OF LISTING WITH NEW YORK STOCK EXCHANGE]
1993
In November of 1993, Newfield completed its initial public offering of common
stock and began trading on the New York Stock Exchange under the symbol "NFX."
5
<PAGE> 7
1994
In late 1993, Newfield Exploration Company acquired the Eugene Island 251/262
Field having identified drilling opportunities using 3-D seismic analysis.
Newfield drilled five successful wells and installed a new platform and
pipeline. Eugene Island 251/262 remains one of Newfield's most significant
fields today, producing 50 MMcfe per day and the Company has additional
drilling ideas in the area. Shown below is the Eugene Island 262 "B" platform.
[PHOTOGRAPH OF EUGENE ISLAND 262 "B" PLATFORM,
OFFSHORE IN THE GULF OF MEXICO]
[PHOTOGRAPH OF FIELD MAP AND SEISMIC LINE
FROM SOUTH TIMBALIER 148 FIELD]
1995
In late 1994, Newfield acquired a farm-in position in the South Timbalier 148
Field and began a drilling program based upon 3-D seismic. During 1995, four
successful exploratory wells and two development wells were drilled.
Subsequently, three platforms were installed and daily production peaked at 100
MMcfe. Shown above are a field map and seismic line from the South
Timbalier 148 Field.
[PHOTOGRAPH OF EWING BANK 947 PLATFORM,
OFFSHORE IN THE GULF OF MEXICO]
1996
A key component of Newfield's strategy is a balanced approach in its capital
program. In 1996, Newfield began drilling activities at newly purchased West
Delta 152 and Ewing Bank 947 (shown above) to test proven undeveloped, probable
and exploratory objectives. The drilling programs were successful and added
significant new reserves. Production in these fields increased to over 100 MMcfe
per day. The fields currently produce 45 MMcfe per day.
1997
A major event of 1997 included the acquisition of interests in the Western Gulf
of Mexico for $43 million. A key prospect was East Cameron 286, on which
Newfield had identified drilling prospects. A successful exploratory well and
four delineation wells were drilled beginning in late 1997 at a new platform
location. Production began from these wells in the fourth quarter of 1998 at
daily rates in excess of 45 MMcfe.
[PHOTOGRAPH OF DRILLING RIG ON LOCATION AT
BROUSSARD AREA, ONSHORE SOUTH LOUISIANA]
1998
A core principle of Newfield's strategy is focus. In late 1995, Newfield
initiated idea generation efforts along the Louisiana Gulf Coast as a natural
extension of its Gulf of Mexico focus area. In early 1998, Newfield drilled a
significant discovery in the Broussard area near Lafayette. The Garber #1
discovery is producing 18 MMcfe per day. A successful follow-up well, the Knight
#1, will be brought on line in 1999 at a similar rate. Shown above is a drilling
rig on location in the Broussard area.
6
<PAGE> 8
[PHOTOGRAPH OF OFFSHORE OIL AND
GAS PLATFORM UNDER CONSTRUCTION]
1989 - 1993
* Company formed in December 1988 with $9 million of capital
* Completed $57 million of private equity placements
* Added 196 Bcfe of new proved reserves, 63 leases and 23 platforms
* Technical staff and seismic database expanded
* Achieved critical mass in Gulf of Mexico
* 26th largest operator of production
* 18th most active driller
* Initial public offering in November 1993 at $8.75 per common share
7
<PAGE> 9
YESTERDAY
1989 - 1993
Newfield was founded by Joe Foster and 24 former employees of Tenneco
Oil's Gulf of Mexico divisions in late 1988, following the sale of Tenneco Oil
by its parent. Foster had been Chairman of Tenneco Oil, a leading Gulf of Mexico
operator.
The concept was to use the kind of technology that had made Tenneco Oil
successful - namely, major company technology with a high geophysical content -
and to combine that with an independent's mindset and cost structure.
Newfield began with $9 million of equity capital, $3 million of which
came from employees, $3 million from a group of investors headed by Charles
Duncan and $3 million from the University of Texas endowment funds. In addition,
it had a $3 million line of credit from the endowment funds. It owned no oil and
gas leases, had no maps and conducted no operations.
[MAP OF NEWFIELD'S ASSET BASE IN GULF
OF MEXICO AS OF DECEMBER 31, 1993]
It did have a group of talented people who had experience working in the
Gulf of Mexico. It was an unusual situation to be able to start a new company
with a group of people who had a common culture and vocabulary, a similar way of
working and one another calibrated.
It was also unusual for a start-up oil and gas company to have twenty
technical and management employees and $2.5 million of annual overhead, with no
assets and no revenue. On Day One, Newfield committed to purchase over $2
million of geophysical data and a $180,000 geophysical work station. As between
first year overhead and data and equipment, half of Newfield's initial capital
went into technology.
By March of 1989, Newfield had drawn enough maps and generated enough
prospects to make five winning bids in a Federal Offshore Lease Sale. Its first
well was drilled in August 1989, and it was a dry hole.
This was followed by two additional dry holes, and another well on which
the drilling rig capsized and the hole was abandoned before reaching its
objective. Fortunately, the rig capsize took place on a turnkey well and
Newfield had no liability.
From the time Newfield secured its initial equity in early 1989, Joe
Foster and David Trice, then the Chief Financial Officer, had been searching for
additional equity capital. By April of 1990, Warburg, Pincus & Co., a large
venture capital investor, and the Yale, Duke and Dartmouth endowments agreed to
join the initial investors in Newfield in purchasing $37 million of new equity.
By the time that financing was closed, Newfield had $100,000 left of its
original capital.
It was in May 1990, that Newfield logged its first discovery. That sam e
week, it closed on its first producing property acquisition, at Eugene Island
172. By the end of 1990, Newfield had made four discoveries and one acquisition
and had the resources to relocate its technical employees from Lafayette,
Louisiana to Houston, where much more of the Gulf of Mexico "deal flow" takes
place. It was a significant improvement to get everyone "under one roof."
In 1990, revenues reached $2.4 million and net income was $0.8 million.
It was a great relief to be paying for overhead out of revenues instead of
stockholders' capital. In 1991, revenues exceeded $10 million, driven by the
acquisition and subsequent drilling at West Cameron 109.
In 1992, despite drilling a string of nine consecutive dry holes,
Newfield's insistence on balancing exploration with a good mix of producing
property acquisitions and its emphasis on keeping its cost structure among the
lowest in the business resulted in $41 million of revenue and a continuation of
its pattern of growth.
The stock market appeal of E&P stocks improved in 1993 and Newfield
began considering a public offering. This was the "exit strategy" its early
private investors had in mind, and it would permit Newfield to deliver on one of
the "carrots" it offered its early employees - profits from stock options and
early stock purchases.
On November 12, 1993, following a 10 day road show for potential
investors that someone characterized as "a whole lot more 'road' than 'show,'"
Newfield began trading at a price of $8.75 per share (stock split adjusted).
Twenty percent of the Company had been sold to the "public." The patience and
foresight of the early investors and employees was rewarded with market
liquidity. Newfield's goal had been to become a public company within five
years. It made it in four years, 10 months! There were congratulations,
celebrations and feelings of success.
Joe Foster, citing Newfield's early struggles and failures, reminded the
employees of the maxim "Failure is never fatal and success is never final." "We
have learned the first part of that," he said, "We must not forget the second
part."
8
<PAGE> 10
[PHOTOGRAPH OF OIL AND GAS PLATFORM
BEING INSTALLED IN THE GULF OF MEXICO]
1994 - 1998
* Solid, steady growth in reserves and production
* Significantly expanded Gulf Coast asset base
* Initiated expansion into selected international areas
* 2-for-1 common stock split
* Received MMS National SAFE Award
* Strong balance sheet and access to capital
* Foundation of qualified people with latest technology in place for
continued growth
9
<PAGE> 11
TODAY
1994 - 1998
Newfield Exploration Company entered 1994 with a solid foundation and a
short, but clear, record of building reserves and adding value. An important
achievement along the way was reaching so-called "critical mass." The test in
upcoming years would be to see if that foundation could continue to support the
Company's rapid growth.
"Up and to the right" is a phrase Newfield likes to use to describe the
Company's growth chart. In 1994, that growth curve flattened slightly as the
Company became accustomed to life as a public company. In 1995, however, almost
every measurement was on the way "up" as Newfield posted gains in reserves (up
27%) and production (up 41%) during the year. Despite the significant growth,
Newfield stayed true to its pledge of keeping costs low. A 1995 report ranking
cost efficiencies of 25 publicly traded oil and gas companies placed Newfield
first in 10 of 12 categories. The year was important for reasons beyond its
continued success. Late in 1995, Newfield began to explore beyond its primary
focus in the Gulf of Mexico and onto dry land. Newfield obtained leases, shot
3-D seismic surveys and began drilling. Today, Newfield's onshore activity is an
increasingly important contributor to the Company's oil and gas reserves. Some
10% of the addition in reserves in 1998 came from onshore wells.
[MAP OF NEWFIELD'S GULF COAST ASSET BASE
AS OF DECEMBER 31, 1998]
In 1996, Newfield achieved record operating results. In the meantime, a
healthy stock market and Newfield's continued achievements enabled the Company
to reward stockholders with a 2-for-1 stock split. The strong ride continued the
following year as total annual revenues rose to just under $200 million. By
1997, Newfield had reviewed possible activities in more than 1,000 Gulf of
Mexico blocks, and had expanded its focus area to onshore Louisiana and to just
beyond the 600-foot water depth line on the continental shelf. A modest effort
began to search internationally for impact projects where Newfield's core
competencies could be applied. In May 1997, Newfield closed the acquisition of
the assets of Huffco International L.L.C., which included rights to drill in the
Bohai Bay, offshore China. And like Newfield's first attempts in the Gulf and
then onshore, the first drilling attempt was not a success. And, as before,
Newfield will make other tries in selected international areas.
"All along our expansion has been systematic," said David Trice, a
founder and initial CFO of Newfield who left to run Huffco and subsequently
rejoined Newfield as Vice President - Finance and International. "If you look at
a map of our expansion, it has come in rings and only when we could maintain our
focus, which is a founding principle of Newfield. It will be just the same as we
expand internationally." Focus became a true challenge in 1998 as events in the
energy industry proved to make 1998 one of the most difficult in Newfield's
history. Oil and gas prices decreased, dropping 25% from 1997 levels. However,
rig costs and marine operation expenses, which hit historical highs for
Newfield, did not fall as quickly. The result was Newfield's most difficult year
in financial terms - oil and gas revenues slipped slightly to $196 million from
$199 million in 1997 and a writedown due to accounting procedures led to a net
loss of $57.7 million. However, there was plenty of good news to report. Proved
oil and gas reserves reached 513 Bcfe, an increase of 18% over 1997. Additions
to Newfield's proved reserve base were 167 Bcfe, a healthy 188% replacement of
production and 1998 production increased 20% to 88.5 Bcfe. Finally, earnings
from operations were $10.4 million for the year. "It wasn't our best year,"
Foster says. "In hindsight I don't think we reacted as quickly as we could have
to the run-up in costs, but we learned some things about operating during a down
year." Most notably, Newfield kept a strong, conservative balance sheet.
Maintaining that strong fiscal posture positions the Company to grow even if the
energy industry continues to slump.
As the curtain was drawn on 1998, ending Newfield's second five year
span, the Company is no longer the unheralded firm it was in 1994. It is now one
of the largest operators in the Gulf of Mexico, with gross operated daily
production of 590 MMcfe. Investors have watched the stock price climb from $8.75
per share at the IPO to $20.88 at the end of 1998. Five years ago, Newfield was
based solely in the shallow waters of the Gulf of Mexico. Today it is branching
outward as a mature Company positioned to take advantage of opportunities around
the globe.
10
<PAGE> 12
[PHOTOGRAPH OF DRILLING RIG ON LOCATION AT NEWFIELD PLATFORM,
OFFSHORE GULF OF MEXICO]
1999 and Beyond
* Clear, competitive strengths in Gulf of Mexico
* Continued expansion within Gulf Coast focus area
* Strong credit statistics and conservative financial strategy
* Application of Gulf of Mexico competencies in selected international areas
* Maintain leadership position in low cost, safe operations
* Production growth of 20% projected in 1999
* Talented, experienced and motivated employees with equity incentives
11
<PAGE> 13
TOMORROW
1999 and Beyond
Much has changed in the ten years since Joe Foster and several former
Tenneco Oil employees bundled their severance packages together to help fund the
creation of Newfield Exploration Company. Once focused solely on the Gulf of
Mexico, the Company now has interests in South Louisiana and South Texas and is
exploring selected opportunities in places such as China, West Africa, Australia
and the East Coast of South America. Once the full-time employee list totaled 25
people, the Company now employs about 100. Once down to its last $100,000 and
scrambling to complete another round of financing, Newfield now has strong
internally generated cash flow and access to capital. Once Newfield had $9
million of capital, the Company now has a total capitalization of almost $1
billion.
[GRAPH SHOWING ANNUAL GROWTH IN NEWFIELD'S DAILY OIL AND GAS PRODUCTION]
By 1998, what had changed the most for Joe Foster, however, were
Mondays. For the first 10 years, Monday mornings always had been when Newfield
staffers gathered to give status reports on all the ongoing projects and to
discuss future opportunities. Ten years ago, those meetings were attended by
about 20 people. By 1998, more than 75 people were squeezing into the conference
room at the corporate headquarters in Houston. Foster began to realize that the
meetings were not as effective as they had once been. "Mondays had always been
the day when all of us - financial, operations, technical, everyone - would get
together and go down the list of every opportunity and discuss every aspect of
it. And we sort of took a blood pact that we would get it done in an hour,"
Foster recalls. "By last year that wasn't happening and we knew we needed to
make some changes."
A restructuring was completed, reorganizing the employee group into four
"teams" to oversee projects in the Eastern Gulf of Mexico, the Western Gulf,
Onshore and International. Each team has between 10 and 20 people, representing
the main technical disciplines. So far the results have been positive, Foster
says. "We wanted to avoid adding layers," he says. "Layers cause problems.
Information gets filtered up and down the chain and that's one thing we've never
had at Newfield. What we really tried is to create "mini-Newfields" and
recapture that feeling of responsibility, autonomy and ownership." Indeed, these
attributes were hallmarks of the business plan that created Newfield.
As the Company moves into its next phase of growth, each team will be
able to re-focus their attention on their specific area of expertise, making
careful decisions that will benefit investors and allow Newfield to adapt more
quickly to the often volatile energy industry. Despite a trying past year,
Newfield's balance sheet and credit statistics remain strong, allowing it to
pursue opportunities that fit its operating strategy.
Indeed one bright spot from 1998 is a healthy backlog of ideas and
opportunities. For 1999, Newfield established a capital budget of $150 million,
including $42 million for exploration activities. Newfield has established a
production goal of 106 Bcfe, a 20% increase over 1998. While the shelf of the
Gulf of Mexico remains a core focus area of high potential, production growth
should increasingly come from expansion onshore in South Louisiana and South
Texas, where Newfield continues to expand its seismic database and opportunity
set. Meanwhile, a successful hedging strategy to mitigate price risk will pay
dividends in 1999 as over 50% of first half 1999 gas production is locked in at
prices not less than $2.20 per Mcf. At the same time, service costs,
particularly rig rates, have significantly eased, which should improve
Newfield's cost structure and cash flow.
Newfield's strong financial position, growing asset base and the
alteration of the corporate structure into four specialized teams to strengthen
the idea generation process give rise to solid optimism for the future. "There
is more enthusiasm at the working level than ever before." says Foster. "And I
think it shows that we can be adaptable, but still maintain our bedrock
principles." Such sentiments demonstrate that no matter how large Newfield
grows, no matter where it is exploring for oil and gas, no matter how much the
operating environment changes, the more it stays the same.
-------------------------------
Securities and Exchange Commission Form 10-K Information. The following pages
include information required to be filed with the Securities and Exchange
Commission on Form 10-K and are incorporated by reference to this Annual Report
in the Company's Form 10-K.
12
<PAGE> 14
[COMPANY PHOTOGRAPH]
<TABLE>
<CAPTION>
1990 1993 1998
---- ---- ----
<S> <C> <C> <C>
NUMBER OF EMPLOYEES 22 43 96
</TABLE>
<TABLE>
<CAPTION>
1990 1993 1998
---- ---- ----
<S> <C> <C> <C>
PROVED RESERVES PER EMPLOYEE 1.1 3.3 5.4
(Bcfe)
</TABLE>
13
<PAGE> 15
[COMPANY PHOTOGRAPH]
<TABLE>
<CAPTION>
1990 1993 1998
------- ------- -------
<S> <C> <C> <C>
PRODUCTION PER EMPLOYEE 44 650 922
(MMcfe)
</TABLE>
<TABLE>
<CAPTION>
1990 1993 1998
------- ------- -------
<S> <C> <C> <C>
REVENUE PER EMPLOYEE $ 0.1 $ 1.4 $ 2.0
($MM)
</TABLE>
14
<PAGE> 16
[PHOTOGRAPH OF HANDSHAKE WITH NEWFIELD BUSINESS PRINCIPLES INTERWOVEN]
GUIDING BUSINESS PRINCIPLES
* Talented People
* Focus
* Emphasis on Technology and Teamwork
* Control of Operations/Low Cost Structure
* Balanced Risks -- Exploration and Acquisitions
* Employee Ownership
15
<PAGE> 17
FINANCIAL INFORMATION
================================================================================
<TABLE>
<S> <C>
Five-Year Financial and Reserve Data ....................................... 18
Management's Discussion and Analysis ....................................... 19
Report of Independent Accountants .......................................... 29
Consolidated Balance Sheet ................................................. 30
Consolidated Statement of Income ........................................... 31
Consolidated Statement of Stockholders' Equity ............................. 32
Consolidated Statement of Cash Flows ....................................... 33
Notes to Consolidated Financial Statements ................................. 34
</TABLE>
================================================================================
16
<PAGE> 18
[INTENTIONALLY LEFT BLANK]
17
<PAGE> 19
SELECTED FIVE-YEAR FINANCIAL AND RESERVE DATA
The following table sets forth selected consolidated financial and reserve
data regarding the Company as of and for each of the periods indicated. The
following data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations," the Company's
consolidated financial statements and notes thereto and supplementary financial
information, which follow.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1998 1997 1996 1995 1994
--------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Oil and gas revenues............................ $195,685 $199,399 $149,256 $ 94,598 $ 69,728
-------- -------- -------- -------- --------
Operating expenses:
Lease operating............................... 35,345 24,308 16,946 14,227 9,555
Depreciation, depletion and amortization...... 123,147 94,000 64,026 49,904 34,118
Ceiling test writedown........................ 104,955 4,254 -- -- --
General and administrative, net............... 9,848 11,093 7,552 5,549 3,802
Stock compensation (1)........................ 2,222 1,177 1,943 692 1,084
-------- -------- -------- -------- --------
Total operating expenses.............. $275,517 $134,832 $ 90,467 $ 70,372 $ 48,559
-------- -------- -------- -------- --------
Income (loss) from operations................... $(79,832) $ 64,567 $ 58,789 $ 24,226 $ 21,169
Interest income (expense), net.................. (8,544) (2,146) 497 780 1,379
-------- -------- -------- -------- --------
Income (loss) before income taxes............... $(88,376) $ 62,421 $ 59,286 $ 25,006 $ 22,548
Income tax provision (benefit).................. (30,677) 21,818 20,792 8,742 8,108
-------- -------- -------- -------- --------
Net income (loss)............................... $(57,699) $ 40,603 $ 38,494 $ 16,264 $ 14,440
======== ======== ======== ======== ========
Basic earnings (loss) per common share.......... $ (1.55) $ 1.14 $ 1.10 $ 0.48 $ 0.43
======== ======== ======== ======== ========
Diluted earnings (loss) per common share........ $ (1.55) $ 1.07 $ 1.03 $ 0.45 $ 0.40
======== ======== ======== ======== ========
Weighted average number of shares outstanding
for basic earnings per share.................. 37,312 35,612 34,872 33,935 33,197
Weighted average number of shares outstanding
for diluted earnings per share (2)............ 37,312 38,017 37,409 36,454 35,974
CASH FLOW DATA:
Net cash provided by operating activities before
changes in operating assets and liabilities... $141,948 $161,852 $125,226 $ 75,613 $ 57,535
Net cash provided by operating activities....... 146,575 160,338 127,494 67,640 68,121
Net cash used in investing activities........... (318,991) (242,962) (159,537) (99,329) (123,619)
Net cash provided by financing activities....... 164,291 77,551 32,800 33,810 865
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital surplus (deficit)............... $ (8,806) $ 372 $ 11,436 $ 11,235 $ 10,987
Oil and gas properties, net..................... 578,423 483,954 328,615 228,509 173,924
Total assets.................................... 629,311 553,621 395,938 277,406 215,557
Long-term debt and capital lease obligations,
less current maturities....................... 208,650 129,623 60,000 25,152 555
Stockholders' equity............................ 323,948 292,048 239,902 193,571 169,491
RESERVE DATA (AT END OF PERIOD):
Proved Reserves:
Oil and condensate (MBbls).................... 15,171 16,307 13,659 9,633 8,610
Gas (MMcf).................................... 422,277 337,481 241,385 203,580 153,967
Total proved reserves (MMcfe)................. 513,304 435,323 323,339 261,378 205,627
Present value of estimated future pre-tax net
cash flows.................................... $549,818 $654,669 $859,817 $364,879 $230,594
</TABLE>
- ---------------
(1) Stock compensation represents non-cash stock compensation charges. See Note
6 to the Company's consolidated financial statements.
(2) See Note 1 of the Company's consolidated financial statements.
18
<PAGE> 20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the
Company's consolidated financial position, cash flows and results of operations
for each year in the three year period ended December 31, 1998. The Company's
consolidated financial statements and the notes thereto that follow contain
detailed information that should be referred to in conjunction with the
following discussion.
GENERAL
As an independent oil and gas producer, the Company's revenue,
profitability and future rate of growth are substantially dependent upon
prevailing prices for natural gas, oil and condensate, which are dependent upon
numerous factors beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of energy. The energy
markets have historically been very volatile, as evidenced by the recent
volatility of oil and gas prices, and there can be no assurance that oil and gas
prices will not be subject to wide fluctuations in the future. A substantial or
extended decline in oil and gas prices could have a material adverse effect on
the Company's financial position, results of operations, cash flows, quantities
of oil and gas reserves that may be economically produced and access to capital.
From time to time, the Company has utilized and expects to continue to
utilize hedging transactions with respect to a portion of its oil and gas
production to achieve a more predictable cash flow, as well as to reduce its
exposure to price fluctuations. See "Hedging."
In addition to the effects of the substantial decline in product prices,
the Company's results of operations for 1998 were adversely affected by higher
costs. The high level of activity in the oil and gas industry in the first half
of 1998 resulted in historically high drilling rig and oil field service costs
and inefficiencies in employing capital. While drilling rig and oil field
service costs began to move downward in the latter part of 1998, Newfield
realized only a marginal improvement in costs because of existing contractual
commitments. As a consequence, Newfield incurred not only significantly higher
lease operating expense but also significantly higher capitalized costs and, as
a result, higher depreciation, depletion and amortization expense. So long as
oil and gas prices remain at low levels, the Company expects drilling rig and
oil field service costs to be lower. If that is the case, the Company should
begin to experience reduced lease operating expense and capitalized costs in
1999 as its contractual commitments expire.
The Company has not in the past, and does not intend to pay cash dividends
on its common stock in the foreseeable future. The Company currently intends to
retain any earnings for the future operation and development of its business. In
addition, the payment of dividends is restricted by the terms of the Company's
credit facility.
The Company uses the full cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including certain related employee costs (less any joint interest
reimbursements for such costs) incurred for the purpose of acquiring and finding
oil and gas reserves are capitalized in a "full cost pool" as incurred. These
costs are grouped into cost centers on a country-by-country basis. The Company
records depletion of its full cost pool using the unit-of-production method and
uses its internal estimates of proved quantities of oil and gas reserves for
financial accounting matters. For each cost center, to the extent that
capitalized costs in a full cost pool (net of depreciation, depletion and
amortization and related deferred taxes) exceed the present value (using a 10%
discount rate) of estimated future net after-tax cash flows from proved oil and
gas reserves, such excess costs are charged to operations. Once incurred, a
writedown of oil and gas properties is not reversible at a later date even if
oil or gas prices increase. Primarily as a result of the recent significant
declines in both oil and gas prices, the Company recorded a ceiling test
writedown at December 31, 1998 (see Note 1 to the Company's consolidated
financial statements). The continued decline in both oil and gas prices since
December 31, 1998 may require the Company to record an additional ceiling test
writedown in the first quarter of 1999.
In June 1998, the Financial Accounting Standards Board (the "FASB") issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("Statement No. 133"). The statement
requires companies to report the fair market value of derivatives on the balance
sheet and record in income or other comprehensive income, as appropriate, any
changes in the fair value of the derivative. Statement No. 133 will become
effective for the Company on January 1, 2000. The Company is currently
evaluating the impact of this statement.
19
<PAGE> 21
A glossary of certain terms used in the oil and gas business is set forth
under the caption "Oil and Gas Terms" at the end of Management's Discussion and
Analysis.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect
to the oil and gas operations of the Company.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
------- ------- -------
<S> <C> <C> <C>
Production:
Oil and condensate (MBbls)................................ 3,643 3,424 2,558
Gas (MMcf)................................................ 66,634 53,505 41,323
Total production (MMcfe).................................. 88,494 74,049 56,670
Average Realized Price:
Oil and condensate (per Bbl).............................. $ 12.75 $ 19.08 $ 20.89
Gas (per Mcf)............................................. 2.25 2.51 2.32
Average Costs (per Mcfe):
Lease operating........................................... $ 0.40 $ 0.33 $ 0.30
Depreciation, depletion and amortization.................. 1.39 1.27 1.13
General and administrative, net........................... 0.11 0.15 0.13
</TABLE>
1998 COMPARED TO 1997
PRODUCTION. Net production increased 20%, from 74.0 Bcfe for 1997 to 88.5
Bcfe for 1998. Oil and condensate production for 1998 increased 219 MBbls, or
6%, compared to 1997. Increased oil production for 1998 was due primarily to
production increases from development drilling activities during 1997 at Ship
Shoal 354, West Delta 152 and High Island 537.
Gas production increased by 13.1 Bcf, or 25%, from 53.5 Bcf for 1997 to
66.6 Bcf for 1998. Increased gas production was due to production increases from
development drilling activities during 1997 at East Cameron 373, West Cameron
561 and the acquisition of interests in nine offshore blocks in the East
Cameron, West Cameron and High Island areas of the Gulf of Mexico in July 1997.
These increases were partially offset by production curtailments as a result of
tropical storm activity during September 1998 and by natural production decline
on other properties.
OIL AND GAS REVENUES. Oil and gas revenues for 1998 decreased by $3.7
million, or 2%, compared to 1997, primarily as a result of significantly lower
realized oil and gas prices partially offset by increased oil and gas
production. The average realized price of natural gas and oil and condensate
decreased by 10% and 33%, respectively.
For 1998, the average realized gas price was $2.25 per Mcf, which, as a
result of hedging activities, was 106% of the $2.12 per Mcf average gas sales
price that would have otherwise been received. As a result of hedging activities
for gas production for 1997, the Company realized an average gas price of $2.51
per Mcf, or 96% of the $2.61 per Mcf average gas sales price that would have
otherwise been received. For 1998, the average realized oil and condensate price
was $12.75 per barrel, which, as a result of hedging activities, was 102% of the
$12.50 per barrel average oil and condensate sales price that would have
otherwise been received. For 1997, the average realized oil and condensate price
was $19.08 per barrel, which, as a result of hedging activities, was 101% of the
$19.05 per barrel average oil and condensate sales price that would have
otherwise been received. During 1998, approximately 61% of the Company's
equivalent production was subject to hedge positions as compared to 64% in 1997.
LEASE OPERATING EXPENSE. Lease operating expense for 1998 increased to
$35.3 million from $24.3 million for 1997. Lease operating expense per Mcfe
increased from $0.33 for 1997 to $0.40 for 1998. These increases are primarily
attributable to a general increase in fees charged by the oil field service
industry, lease operating costs associated with properties acquired after
December 31, 1997 and lease operating costs associated with the initiation of
production at East Cameron 373.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. During 1998,
depreciation, depletion and amortization expense increased to $123.1 million
from $94.0 million for 1997. The increase was the result of an increased
depletion rate per Mcfe and production increases from acquisitions and
exploratory and development
20
<PAGE> 22
drilling activities during 1997 and 1998. The increase in the depletion rate per
Mcfe from $1.27 for 1997 to $1.39 for 1998 is primarily attributable to a
general increase in the costs of drilling goods and services, platform and
facilities construction and transportation services to the industry.
CEILING TEST WRITEDOWN. A non-cash writedown of $105.0 million (resulting
in a charge to earnings of $68.3 million after-tax) in the carrying value of the
Company's oil and gas properties was recognized at December 31, 1998. The charge
resulted from the application of the full cost "ceiling test" (see Note 1 to the
Company's consolidated financial statements). The writedown is primarily
attributable to lower prices for both oil and natural gas at December 31, 1998.
GENERAL AND ADMINISTRATIVE EXPENSE, NET. General and administrative
expense, which is net of overhead reimbursements received by the Company from
other working interest owners, decreased to $9.8 million, or $0.11 per Mcfe for
1998, as compared to $11.1 million, or $0.15 per Mcfe, for 1997. The decrease
per Mcfe is due to increased production during 1998 and a decrease in
performance-based compensation. Performance-based compensation, as a component
of general and administrative expense, decreased from $5.3 million, or $0.07 per
Mcfe, for 1997 to $1.9 million, or $0.02 per Mcfe, for 1998. General and
administrative expenses exclusive of performance-based compensation did,
however, increase, from $5.8 million, or $0.08 per Mcfe, for 1997 to $7.9
million, or $0.09 per Mcfe, for 1998. These increases are primarily attributable
to direct costs associated with staff increases during 1997 and 1998 and were
partially offset by joint interest reimbursements. To the extent that the
Company continues to grow and increase its ownership in certain properties, the
Company expects general and administrative expenses, in the aggregate, to
increase.
STOCK COMPENSATION EXPENSE. Stock compensation expense increased by $1.0
million during 1998 due to the amortization of additional non-cash compensation
expense associated with 105,100 shares of restricted stock that were granted in
1998 to employees and 8,568 shares of restricted stock that were granted to
non-employee Directors.
INTEREST EXPENSE, NET. Interest expense, net of capitalized interest, for
1998 increased to $9.5 million from $3.3 million for 1997. The increase was
attributable to higher average debt levels during 1998 and a lower percentage of
total interest costs incurred being capitalized.
NET INCOME. As a result of the foregoing, particularly the ceiling test
writedown and the substantial decrease in realized oil and gas prices for 1998
compared to 1997, the Company had a net loss of $57.7 million, or $1.55 per
diluted share, for 1998 as compared to net income of $40.6 million, or $1.07 per
diluted share, for 1997.
1997 COMPARED TO 1996
PRODUCTION. Net production increased 31%, from 56.7 Bcfe for 1996 to 74.0
Bcfe for 1997. Oil and condensate production for 1997 increased 866 MBbls, or
34%, compared to 1996. Increased oil production for 1997 was due primarily to
production increases from development drilling activities during 1996 at South
Timbalier 148 and Ewing Bank 947, the acquisition of Ship Shoal 69 in the third
quarter of 1996 and a well drilled and placed on production late in the fourth
quarter of 1996 at Vermilion 398. Gas production increased by 12.2 Bcf, or 29%,
from 41.3 Bcf for 1996 to 53.5 Bcf for 1997. Increased gas production was due to
production increases from development drilling activities during 1996 at South
Timbalier 148 and Ewing Bank 947, the acquisition of interests in nine offshore
blocks in the East Cameron, West Cameron and High Island areas of the Gulf of
Mexico in July 1997, and wells drilled and placed on production during the
fourth quarter of 1996 at Vermilion 308 and Vermilion 398. These increases were
partially offset by natural production decline on other properties of the
Company.
OIL AND GAS REVENUES. Oil and gas revenues for 1997 increased by $50.1
million, or 34%, compared to 1996, primarily as a result of increased oil and
gas production and higher realized gas prices. The average realized price of
natural gas increased by 8%.
For 1997, the average realized gas price was $2.51 per Mcf, which, as a
result of hedging activities, was 96% of the $2.61 per Mcf average gas sales
price that would have otherwise been received. As a result of hedging activities
for gas production for 1996, the Company realized an average gas price of $2.32
per Mcf, or 86% of the $2.70 per Mcf average gas sales price that would have
otherwise been received. For 1997, the average realized oil and condensate price
was $19.08 per barrel, which, as a result of hedging activities, was 101% of the
$19.05 per barrel average oil and condensate sales price that would have
otherwise been received. For 1996, the average realized oil and condensate price
was $20.89 per barrel, which as a result of hedging activities, was 99% of the
$21.15 per barrel average oil and
21
<PAGE> 23
condensate sales price that would have otherwise been received. During 1997,
approximately 64% of the Company's equivalent production was subject to hedge
positions as compared to 54% in 1996.
LEASE OPERATING EXPENSE. Lease operating expense for 1997 increased to
$24.3 million from $16.9 million for 1996. Lease operating expense per Mcfe
increased from $0.30 for 1996 to $0.33 for 1997. These increases are primarily
attributable to a general increase in costs in the oil field service industry,
increased workover activities and lease operating costs associated with
properties acquired during 1997 and 1996.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. During 1997,
depreciation, depletion and amortization expense increased to $94.0 million from
$64.0 million for 1996. The increase was the result of an increased depletion
rate per Mcfe and production increases from acquisitions and exploratory and
development drilling activities during 1996 and 1997. The depletion rate per
unit for 1997 increased to $1.27 per Mcfe, from $1.13 per Mcfe for 1996. The
increase in the depletion rate per unit is primarily attributable to increased
costs of drilling goods and services, platforms and facilities construction and
transportation services in the industry.
CHINA CEILING TEST WRITEDOWN. During 1997, the Company completed the
drilling of its initial exploratory well in the Bohai Bay, offshore China at a
cost of $4.3 million. The well did not encounter commercial quantities of oil or
gas and the participants in the well agreed to plug and abandon it. As a result,
in accordance with full cost accounting rules the Company recorded a writedown
of its investment by the amount of the cost of the well.
GENERAL AND ADMINISTRATIVE EXPENSE, NET. General and administrative
expense, which is net of overhead reimbursements received by the Company from
other working interest owners, increased to $11.1 million, or $0.15 per Mcfe for
1997, as compared to $7.6 million, or $0.13 per Mcfe, for 1996. Performance
based compensation, as a component of general and administrative expense,
increased from $4.9 million, or $0.09 per Mcfe for 1996 to $5.3 million, or
$0.07 per Mcfe for 1997. Direct costs associated with staff increases during
1996 were partially offset by joint interest reimbursements.
INTEREST EXPENSE, NET. Interest expense, net of capitalized interest, for
1997 increased to $3.3 million from $0.4 million for 1996. The increase was
attributable to higher average debt levels during 1997 and a lower percentage of
total interest cost being capitalized.
NET INCOME. As a result of the foregoing, the Company had net income of
$40.6 million, or $1.07 per diluted share, for 1997, as compared to $38.5
million, or $1.03 per diluted share, for 1996.
LIQUIDITY AND CAPITAL RESOURCES
The Company had a working capital deficit of $8.8 million at December 31,
1998 compared to a working capital surplus of $0.4 million at December 31, 1997.
The $9.2 million decrease in working capital is primarily due to the substantial
decrease in realized oil and gas prices at December 31, 1998 compared to
December 31, 1997 and management's decision to maintain lower levels of cash and
therefore reduce interest expense. Long-term debt increased from $129.6 million
at December 31, 1997 to $208.7 million at December 31, 1998. Working capital
balances may fluctuate from year to year to the extent the Company increases or
decreases borrowings under its revolving credit facility (the "Credit
Facility"). The Company has funded its oil and gas activities through cash flow
from operations, equity capital from private and public sources, public debt and
bank borrowings.
The Company filed a "universal shelf" registration statement with the
Securities and Exchange Commission with respect to the offering and sale of an
array of debt and equity securities in July 1998 in order to better position
itself to take advantage of future opportunities and to provide financing
alternatives. In September 1998, the Company completed the sale of four million
newly issued shares of its common stock under this registration statement. The
Company used the $83 million of net proceeds to reduce outstanding debt under
its Credit Facility.
The Company maintains its reserve-based revolving Credit Facility with
Chase Bank of Texas, National Association, as agent. As of December 31, 1998,
$84 million was outstanding under the Credit Facility. The Credit Facility
provides a $225 million revolving credit maturing on October 31, 2002. The
amount available under the Credit Facility is subject to a calculated borrowing
base determined by a majority of the banks participating in the Credit Facility,
which is reduced by the aggregate principal outstanding on the Company's senior
unsecured notes (currently $125 million) (as so reduced, the "Borrowing Base").
The Borrowing Base is currently $175 million, but no assurances can be given
that a majority of the banks will not elect to redetermine the Borrowing Base in
the future. The Company has an option, subject to the Borrowing Base, to
increase the facility to $250 million. Without so increasing the facility,
22
<PAGE> 24
the Company currently has approximately $91 million of available capacity under
the Credit Facility as of February 15, 1999.
The Company has also established money market lines of credit with various
banks in an amount limited by the Credit Facility to $25 million. As of December
31, 1998, there were no borrowings outstanding under these lines of credit.
The Company considers its interest rate risk exposure to be minimal because
$125 million, or approximately 60% of its total debt at December 31, 1998, is
subject to a fixed interest rate. As a result, if the amount of the Company's
floating rate debt remained unchanged from December 31, 1998, interest costs
with respect to only $84 million of debt would be subject to fluctuation based
on short-term interest rates in 1999. The impact on annual cash flow of a 10%
change in the floating rate (approximately 57 basis points) applicable to such
debt would be $0.5 million.
The Company's net cash flow from operations for 1998 was $146.6 million
compared to $160.3 million for 1997. The decrease is primarily due to decreases
in oil and gas revenues, partially offset by changes in operating assets and
liabilities. Net cash flow from operations before changes in operating assets
and liabilities for 1998 was $141.9 million compared to $161.9 million for 1997.
The year-to-year decrease in net cash flow from operations before changes in
operating assets and liabilities is primarily attributable to decreased average
realized oil and gas prices and higher operating expenses offset by increased
oil and gas production.
Capital expenditures for 1998 were $310.8 million, consisting of $65.3
million for exploration, $155.9 million for development and $89.6 million for
property acquisitions. The Company has budgeted $150 million for capital
spending in 1999. Of that amount, $42 million has been allocated to exploration
projects and $57 million has been allocated to identified development drilling
projects and the construction of platforms, facilities and pipelines (including
$5 million relating to the abandonment or dismantlement of existing wells and
facilities). The Company continues to pursue attractive acquisition
opportunities. The timing and size of any acquisition and the associated capital
commitments are unpredictable.
Actual levels of capital expenditures may vary significantly due to many
factors, including drilling results, oil and gas prices, industry conditions,
the prices and availability of goods and services and the extent to which proved
properties are acquired. The Company anticipates that capital expenditures will
be funded principally from cash flow from operations, working capital and bank
borrowings. During 1998, the Company borrowed $795.8 million and repaid $716.8
million under the Credit Facility and its money market lines of credit. The
Company anticipates additional borrowings under the Credit Facility and its
money market lines of credit during 1999.
To cover the various obligations of lessees on the Outer Continental Shelf
(the "OCS"), the MMS generally requires that lessees post substantial bonds or
other acceptable assurances that such obligations will be met. The cost of such
bonds or other surety can be substantial and there is no assurance that bonds or
other surety can be obtained in all cases. Additionally, the MMS may require
operators in the OCS to post supplemental bonds in excess of lease and area wide
bonds to assure that abandonment obligations on specific properties will be met.
The Company is currently exempt from the supplemental bonding requirements of
the MMS. Under certain circumstances, the MMS may require any operator's
activities on federal leases to be suspended or terminated. Any such suspension
or termination of the Company's operations could materially and adversely affect
the Company's financial position, cash flows and results of operations.
The Company's operations are subject to various federal, state and local
laws and regulations relating to the protection of the environment. The Company
believes its current operations are in material compliance with current
environmental laws and regulations. There can be no assurance, however, that
current regulatory requirements will not change, currently unforeseen
environmental incidents will not occur or past non-compliance with environmental
laws will not be discovered.
The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows or results of
operations of the Company.
HEDGING
From time to time, the Company has utilized and expects to continue to
utilize hedging transactions with respect to a portion of its oil and gas
production to achieve a more predictable cash flow, as well as to reduce its
exposure to
23
<PAGE> 25
price fluctuations. While the use of these hedging arrangements limits the
downside risk of adverse price movements, they may also limit future revenues
from favorable price movements. The use of hedging transactions also involves
the risk that the counterparties will be unable to meet the financial terms of
such transactions. Substantially all of the Company's hedging transactions to
date were carried out in the over-the-counter market and the obligations of the
counterparties have been guaranteed by entities with at least an investment
grade rating or secured by letters of credit. The Company accounts for these
transactions as hedging activities and, accordingly, gains or losses are
included in oil and gas revenues when the hedged production is delivered.
Neither the hedging contracts nor the unrealized gains or losses on these
contracts are recognized in the financial statements.
As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its 1999 and 2000 natural gas production as
follows:
<TABLE>
<CAPTION>
NYMEX CONTRACT
PRICE PER MMBTU
---------------------------------------------------
COLLARS
VOLUME IN SWAPS ------------------------- FLOOR FAIR MARKET
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
- ------------------------------------------------- --------- --------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
January 1999-March 1999
Price Swap Contracts........................... 2,430 $2.45 -- -- -- $1.5 million
Collar Contracts............................... 5,600 -- $2.25-$2.58 $2.69-$3.50 -- $3.5 million
Floor Contracts................................ 1,800 -- -- -- $2.30-$2.63 $1.0 million
April 1999-June 1999
Price Swap Contracts........................... 930 $2.25 -- -- -- $0.3 million
Collar Contracts............................... 7,000 -- $2.10-$2.15 $2.25-$2.50 -- $1.4 million
July 1999-September 1999
Price Swap Contracts........................... 930 $2.24 -- -- -- $0.3 million
Collar Contracts............................... 3,750 -- $2.10 $2.40 -- $0.5 million
October 1999-December 1999
Price Swap Contracts........................... 930 $2.40 -- -- -- $0.2 million
January 2000-December 2000
Price Swap Contracts........................... 3,000 $2.31 -- -- -- $0.3 million
</TABLE>
- ---------------
(1) Fair market value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 1998.
Additionally, the Company will recognize approximately $2.0 million and
$0.4 million of gas revenue in the first and second quarter of 1999,
respectively, as a result of closing a portion of its natural gas hedge
positions in December 1998 and a portion of the above positions in January 1999.
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or
occasionally, the penultimate trading day of a particular contract month (the
"settlement price"). With respect to any particular swap transaction, the
counterparty is required to make a payment to the Company in the event that the
settlement price for any settlement period is less than the swap price for such
transaction, and the Company is required to make payment to the counterparty in
the event that the settlement price for any settlement period is greater than
the swap price for such transaction. For any particular collar transaction, the
counterparty is required to make a payment to the Company if the settlement
price for any settlement period is below the floor price for such transaction,
and the Company is required to make payment to the counterparty if the
settlement price for any settlement period is above the ceiling price for such
transaction. For any particular floor transaction, the counterparty is required
to make a payment to the Company if the settlement price for any settlement
period is below the floor price for such transaction. The Company is not
required to make any payment in connection with the settlement of a floor
transaction.
The Company has not entered into basis swaps with respect to any of its
currently open hedging transactions. Because substantially all of the Company's
natural gas production is sold under spot contracts that have historically
correlated with the swap price, the Company believes that it has no material
basis risk with respect to gas swaps that are not coupled with basis swaps.
24
<PAGE> 26
As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1999 as follows:
<TABLE>
<CAPTION>
COLLARS
-----------------------------------------
NYMEX
CONTRACT PRICE
PER BBL
VOLUME IN ----------------------------- FAIR MARKET
PERIOD BBLS FLOORS CEILINGS VALUE(1)
- ------------------------------------------------ --------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
January 1999-March 1999......................... 180,000 $15.00-$17.00 $17.00-$18.00 $0.7 million
April 1999-June 1999............................ 182,000 $15.00-$17.00 $17.00-$18.70 $0.7 million
July 1999-September 1999........................ 184,000 $15.00-$17.00 $17.00-$19.15 $0.6 million
October 1999-December 1999...................... 92,000 $15.00 $17.00 $0.2 million
</TABLE>
- ---------------
(1) Fair market value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 1998.
Because substantially all of the Company's oil production is sold under
spot contracts that correlate to the NYMEX West Texas Intermediate price, the
Company believes that it has no material basis risk with respect to these
transactions. The actual cash price the Company receives, however, generally is
$1.50 - $2.00 per barrel less than the NYMEX West Texas Intermediate price when
adjusted for location and quality differences.
YEAR 2000 ISSUES
Year 2000 issues result from the inability of computer programs or
computerized equipment to accurately calculate, store or use a date subsequent
to December 31, 1999. The erroneous date can be interpreted in a number of
different ways; typically the year 2000 is interpreted as the year 1900. 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.
Because the Company's software systems are relatively new, the Company was
aware of and considered Year 2000 issues at the time of purchase or development
of such systems. In addition, the Company has recently completed an assessment
of its core financial and operational software systems to ensure compliance. The
licensor of the Company's core financial software system has certified that such
software is Year 2000 compliant. Additionally, other less critical software
systems and various types of equipment have been assessed and are believed to be
compliant. The Company believes that the potential impact, if any, of these less
critical systems not being Year 2000 compliant will at most require employees to
manually complete otherwise automated tasks or calculations and it should not
impact the Company's ability to continue exploration, drilling, production or
sales activities.
The Company has initiated and will continue to have formal communications
with its significant suppliers, business partners and customers to determine the
extent to which the Company is vulnerable to those third parties' failure to
correct their own Year 2000 issues. There can be no guarantee, however, that the
systems of other companies on which the Company's systems rely will be timely
converted, or that a failure to convert by another company, or a conversion that
is incompatible with the Company's systems would not have a material adverse
effect on the Company. The Company has determined it has no exposure to
contingencies related to the Year 2000 issue with respect to products sold to
third parties.
The Company has and will utilize both internal and external resources to
complete tasks and perform testing necessary to address the Year 2000 issue. The
Company has substantially completed the Year 2000 project. The Company has not
incurred, and does not anticipate that it will incur, any significant costs
relating to the assessment and remediation of Year 2000 issues.
FORWARD-LOOKING STATEMENTS
This Annual Report includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical facts
included in this document, including statements regarding production targets,
anticipated production rates, planned capital expenditures, the availability of
capital resources to fund capital expenditures, estimates of proved reserves,
wells planned to be drilled in the future, the Company's financial position,
business strategy and other plans
25
<PAGE> 27
and objectives for future operations, are forward-looking statements. Although
the Company believes that the expectations reflected in such forward-looking
statements are reasonable, such statements are based upon assumptions and
anticipated results that are subject to numerous uncertainties. Actual results
may vary significantly from those anticipated due to many factors, including
drilling results, oil and gas prices, industry conditions, the prices of goods
and services, the availability of drilling rigs and other support services and
the availability of capital resources. In addition, the drilling of oil and gas
wells and the production of hydrocarbons are subject to governmental regulations
and operating risks.
There are also numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production
and timing of development expenditures, including many factors beyond the
control of the Company. Reserve engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revisions of such
estimate and such revisions, if significant, would change the schedule of any
further production and development drilling. Accordingly, reserve estimates are
generally different from the quantities of oil and natural gas that are
ultimately recovered. 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 such factors.
OIL AND GAS TERMS
Set forth below are definitions of certain terms used in the oil and gas
business.
Basis Risk. The risk associated with the sales point price for oil or gas
production varying from the reference (or settlement) price for a particular
hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per
day.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.
MMS. The Minerals Management Service of the United States Department of the
Interior.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil condensate or natural gas liquids.
NYMEX. New York Merchantile Exchange.
Present value. When used with respect to oil and natural gas reserves, the
estimated value of future gross revenues (estimated in accordance with the
requirements of the Securities and Exchange Commission) to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date indicated,
without giving effect to non-property related expenses such as
26
<PAGE> 28
general and administrative expenses, debt service and future income tax expenses
or to depreciation, depletion and amortization, discounted using an annual
discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved developed reserves. Proved results that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Turnkey drilling contract. A fixed rate contract pursuant to which the
drilling contractor generally bears the risk of loss for unbudgeted
contingencies.
27
<PAGE> 29
MANAGEMENT REPORT ON FINANCIAL STATEMENTS
The Management of Newfield Exploration Company is responsible for the
preparation and integrity of all information contained in this Annual Report.
The financial statements and other financial information are prepared in
accordance with generally accepted accounting principles and, accordingly,
include certain informed judgments and estimates of management. The Company's
independent public accountants have audited the financial statements as
described in their report which follows.
Management maintains a system of internal accounting and managerial
controls which are designed to provide reasonable assurance that assets are
safeguarded, transactions are executed in accordance with management's
authorization and accounting records are reliable for financial statement
preparation.
An Audit Committee of the Board of Directors, consisting of directors who
are not employees of the Company, meets periodically with management and the
independent public accountants to obtain assurances as to the integrity of the
Company's accounting and financial reporting and to affirm the adequacy of the
system of accounting and managerial controls in place. The independent
accountants have full, free and separate access to the Audit Committee to
discuss all appropriate matters.
We believe that the Company's policies and system of accounting and
managerial controls reasonably assure the integrity of the information in the
financial statements and in the other sections of this Annual Report.
<TABLE>
<S> <C>
/s/JOE B. FOSTER /s/TERRY W. RATHERT
Joe B. Foster Chairman of the Board, President and Chief Terry W. Rathert Vice President - Planning and
Executive Officer Administration and Secretary
</TABLE>
28
<PAGE> 30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of
Newfield Exploration Company:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, stockholders' equity and cash flows present
fairly, in all material respects, the financial position of Newfield Exploration
Company and its subsidiaries at 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. 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 of these statements in
accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Houston, Texas
February 12, 1999
29
<PAGE> 31
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1998 1997
ASSETS --------- ---------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 92 $ 8,217
Accounts receivable - oil and gas......................... 43,095 54,123
Other..................................................... 2,082 2,426
--------- ---------
Total current assets.............................. 45,269 64,766
--------- ---------
Oil and gas properties (full cost method, of which $34,234
at December 31, 1998 and $79,264 at December 31, 1997 were
excluded from amortization)............................... 992,629 775,585
Less - accumulated depreciation, depletion and
amortization.............................................. (414,206) (291,631)
--------- ---------
578,423 483,954
--------- ---------
Furniture, fixtures and equipment, net...................... 2,208 1,620
Other assets................................................ 3,411 3,281
--------- ---------
Total assets...................................... $ 629,311 $ 553,621
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities.................. $ 52,123 $ 63,834
Advances from joint owners................................ 1,952 560
--------- ---------
Total current liabilities......................... 54,075 64,394
--------- ---------
Other liabilities........................................... 11,467 3,846
Long-term debt.............................................. 208,650 129,623
Deferred taxes.............................................. 31,171 63,710
--------- ---------
Total long-term liabilities....................... 251,288 197,179
--------- ---------
Commitments and contingencies............................... -- --
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000 shares
authorized; no shares
issued)................................................ -- --
Common stock ($0.01 par value, 100,000,000 shares
authorized; 40,429,729 and 35,975,777 shares issued and
outstanding at December 31, 1998 and December 31, 1997,
respectively).......................................... 404 360
Additional paid-in capital................................ 250,642 160,672
Unearned compensation..................................... (5,007) (4,592)
Retained earnings......................................... 77,909 135,608
--------- ---------
Total stockholders' equity........................ 323,948 292,048
--------- ---------
Total liabilities and stockholders' equity........ $ 629,311 $ 553,621
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
30
<PAGE> 32
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Oil and gas revenues........................................ $ 195,685 $ 199,399 $ 149,256
----------- ----------- -----------
Operating expenses:
Lease operating........................................... 35,345 24,308 16,946
Depreciation, depletion and amortization.................. 123,147 94,000 64,026
Ceiling test writedown.................................... 104,955 4,254 --
General and administrative, net........................... 9,848 11,093 7,552
Stock compensation........................................ 2,222 1,177 1,943
----------- ----------- -----------
Total operating expenses............................... 275,517 134,832 90,467
----------- ----------- -----------
Income (loss) from operations............................... (79,832) 64,567 58,789
Other income (expenses):
Interest income........................................... 964 1,122 917
Interest expense, net..................................... (9,508) (3,268) (420)
----------- ----------- -----------
(8,544) (2,146) 497
----------- ----------- -----------
Income (loss) before income taxes........................... (88,376) 62,421 59,286
Income tax provision (benefit):
Current................................................... -- -- 29
Deferred.................................................. (30,677) 21,818 20,763
----------- ----------- -----------
(30,677) 21,818 20,792
----------- ----------- -----------
Net income (loss)........................................... $ (57,699) $ 40,603 $ 38,494
=========== =========== ===========
Basic earnings (loss) per common share...................... $ (1.55) $ 1.14 $ 1.10
=========== =========== ===========
Diluted earnings (loss) per common share.................... $ (1.55) $ 1.07 $ 1.03
=========== =========== ===========
Weighted average number of shares outstanding for basic
earnings per share........................................ 37,311,928 35,612,488 34,872,113
Weighted average number of shares outstanding for diluted
earnings per share........................................ 37,311,928 38,017,177 37,408,924
</TABLE>
The accompanying notes are an integral part of these financial statements.
31
<PAGE> 33
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL TOTAL
------------------- PAID-IN UNEARNED RETAINED STOCKHOLDERS'
SHARES AMOUNT CAPITAL COMPENSATION EARNINGS EQUITY
---------- ------ ---------- ------------ -------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995...................... 34,354,844 $ 343 $ 137,830 $(1,113) $ 56,511 $ 193,571
Issuance of common stock...................... 632,196 6 3,204 3,210
Issuance of restricted stock, less
amortization of $1,441...................... 256,000 3 3,601 (2,163) 1,441
Cancellation of stock options................. (28) 3 (25)
Amortization of stock compensation............ 527 527
Tax benefit from exercise of stock options
(Note 6).................................... 2,684 2,684
Net income.................................... 38,494 38,494
---------- ----- --------- ------- -------- ---------
Balance, December 31, 1996...................... 35,243,040 352 147,291 (2,746) 95,005 239,902
Issuance of common stock...................... 686,915 7 8,088 8,095
Issuance of restricted stock, less
amortization of $226........................ 45,822 1 3,022 (2,797) 226
Amortization of stock compensation............ 951 951
Tax benefit from exercise of stock options
(Note 6).................................... 2,271 2,271
Net income.................................... 40,603 40,603
---------- ----- --------- ------- -------- ---------
Balance, December 31, 1997...................... 35,975,777 360 160,672 (4,592) 135,608 292,048
Issuance of common stock...................... 4,341,620 43 85,472 85,515
Issuance of restricted stock, less
amortization of $583........................ 115,668 1 2,706 (2,124) 583
Cancellation of restricted stock.............. (3,336) (70) 50 (20)
Amortization of stock compensation............ 1,659 1,659
Tax benefit from exercise of stock options
(Note 6).................................... 1,862 1,862
Net loss...................................... (57,699) (57,699)
---------- ----- --------- ------- -------- ---------
Balance, December 31, 1998...................... 40,429,729 $ 404 $ 250,642 $(5,007) $ 77,909 $ 323,948
========== ===== ========= ======= ======== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
32
<PAGE> 34
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)......................................... $ (57,699) $ 40,603 $ 38,494
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization.................. 123,147 94,000 64,026
Ceiling test writedown.................................... 104,955 4,254 --
Deferred taxes............................................ (30,677) 21,818 20,763
Stock compensation........................................ 2,222 1,177 1,943
--------- --------- ---------
141,948 161,852 125,226
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and gas... 11,028 (7,309) (21,418)
(Increase) decrease in other current assets............... 344 (1,226) 3,793
(Increase) decrease in other assets....................... (130) 1,359 443
Increase (decrease) in accounts payable and accrued
liabilities............................................ (4,652) 6,912 16,523
Increase (decrease) in advances from joint owners......... 1,392 (3,052) 1,939
Increase (decrease) in other liabilities.................. (3,355) 1,802 988
--------- --------- ---------
Net cash provided by operating activities......... 146,575 160,338 127,494
--------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties....................... (317,831) (242,309) (158,834)
Additions to furniture, fixtures and equipment............ (1,160) (653) (703)
--------- --------- ---------
Net cash used in investing activities............. (318,991) (242,962) (159,537)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings.................................. 795,750 357,250 281,000
Repayments of borrowings.................................. (716,750) (412,250) (251,000)
Proceeds from issuance of senior notes.................... -- 124,619 --
Proceeds from issuances of common stock, net.............. 85,291 8,095 3,210
Payments on capital lease obligations..................... -- (163) (410)
--------- --------- ---------
Net cash provided by financing activities......... 164,291 77,551 32,800
--------- --------- ---------
Increase (decrease) in cash and cash equivalents............ (8,125) (5,073) 757
Cash and cash equivalents, beginning of period.............. 8,217 13,290 12,533
--------- --------- ---------
Cash and cash equivalents, end of period.................... $ 92 $ 8,217 $ 13,290
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
33
<PAGE> 35
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization and Principles of Consolidation
These financial statements include the accounts of Newfield Exploration
Company and its subsidiaries (collectively, the "Company"), a Delaware
corporation. All significant intercompany balances and transactions have been
eliminated. The Company was formed on December 5, 1988 to conduct offshore oil
and gas exploration and drilling and development operations in the Gulf of
Mexico. The Company has expanded its operations into onshore South Louisiana and
Texas and select international areas. The Company conducts foreign operations
through its subsidiaries. As an independent oil and gas producer, the Company's
revenue, profitability and future rate of growth are substantially dependent
upon prevailing prices for natural gas, oil and condensate, which are dependent
upon numerous factors beyond the Company's control, such as economic, political
and regulatory developments and competition from other sources of energy. The
energy markets have historically been very volatile, as evidenced by the recent
volatility of oil and gas prices, and there can be no assurance that oil and gas
prices will not be subject to wide fluctuations in the future. A substantial or
extended decline in oil and gas prices could have a material adverse effect on
the Company's financial position, results of operations, cash flows, quantities
of oil and gas reserves that may be economically produced and access to capital.
Reclassifications and 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 and
disclosure of contingent assets and liabilities at the date(s) of the financial
statements and the reported amounts of revenues and expenses during the
reporting period(s). The Company's most significant financial estimates are
based on remaining proved oil and gas reserves (see Supplementary Oil and Gas
Disclosures included in Supplementary Financial Information). Actual results
could differ from these estimates. Certain reclassifications for prior years
have been made to conform with the current year presentation.
Earnings Per Share
Basic earnings (loss) per common share ("EPS") is computed by dividing net
income (loss) by the weighted average number of common shares outstanding for
the period. Diluted EPS reflects the potential dilution that could occur if
securities were exercised or converted to common stock.
There are no adjustments to reported net income (loss) for purposes of
calculating earnings per share. The following is a calculation of basic and
diluted weighted average shares outstanding for each of the three years in the
period ended December 31, 1998:
<TABLE>
<CAPTION>
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
Shares outstanding for basic EPS......................... 37,311,928 35,612,488 34,872,113
Dilution effect of stock options outstanding at end of
period................................................. -- 2,404,689 2,536,811
---------- ---------- ----------
Shares outstanding for diluted EPS....................... 37,311,928 38,017,177 37,408,924
========== ========== ==========
</TABLE>
The calculation of shares outstanding for diluted EPS above does not
include the effect of stock options outstanding at December 31, 1998 of
2,143,349 shares, because to do so would have been antidilutive.
Financial Instruments
Cash equivalents include highly liquid investments with a maturity of
approximately three months or less when acquired. The Company invests cash in
excess of operating requirements in United States Treasury notes, Eurodollar
bonds and investment grade commercial paper. Cash equivalents are stated at
cost, which approximates fair market value.
34
<PAGE> 36
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company includes fair value information in the notes to financial
statements when the fair value of its financial instruments is different from
the book value. The book value of those financial instruments that are
classified as current assets or liabilities approximate fair value because of
the short maturity of those instruments.
The Company enters into various commodity price hedging contracts with
respect to its oil and gas production. While the use of these hedging
arrangements limits the downside risk of adverse price movements, they may also
limit future revenues from favorable price movements. The use of hedging
transactions also involves the risk that the counterparties will be unable to
meet the financial terms of such transactions. Such contracts are accounted for
as hedges, in accordance with Statement of Financial Accounting Standards No.
80. Gains and losses on these contracts are recognized in revenue in the period
in which the underlying production is delivered. These instruments are measured
for correlation at both the inception of the contract and on an ongoing basis.
If these instruments cease to meet the criteria for deferral accounting, any
subsequent gains or losses are recognized in revenue. If these instruments are
terminated prior to maturity, resulting gains and losses continue to be deferred
until the hedged item is recognized in revenue. Neither the hedging contracts
nor the unrealized gains or losses on these contracts are recognized in the
financial statements.
Oil and Gas Properties
The Company uses the full cost method of accounting. Under this method, all
costs incurred in the acquisition, exploration and development of oil and gas
properties are capitalized into cost centers that are established on a
country-by-country basis. Such capitalized costs and estimated future
development and dismantlement costs are amortized on a unit-of-production method
based on proved reserves. For each cost center, the net capitalized costs of oil
and gas properties are limited to the lower of unamortized cost or the cost
center ceiling, defined as the sum of the present value (10% discount rate) of
estimated future net revenues from proved reserves, based on year-end oil and
gas prices; plus the cost of properties not being amortized, if any; plus the
lower of cost or estimated fair value of unproved properties included in the
costs being amortized, if any; less related income tax effects. As required by
these rules, a non-cash writedown of oil and gas properties of $105.0 million
(resulting in a charge to earnings of $68.3 million after-tax) was recognized at
December 31, 1998. The writedown is primarily attributable to the lower prices
for both oil and natural gas at December 31, 1998. In accordance with full cost
accounting rules the Company recorded a writedown of $4.3 million in 1997
related to an unsuccessful well in China.
Proceeds from the sale of oil and gas properties are applied to reduce the
costs in the cost center unless the sale involves a significant quantity of
reserves in relation to the cost center, in which case a gain or loss is
recognized.
Unevaluated properties and associated costs not currently being amortized
and included in oil and gas properties were $25.1 million and $71.4 million at
December 31, 1998 and 1997, respectively. Additionally, at December 31, 1998 and
1997, there was $9.2 million and $7.9 million, respectively, of unproved
property costs associated with the Company's investment in international
activities. The properties represented by these costs were at such dates
undergoing exploration activities, or are properties on which the Company
intends to commence such activities in the future. The Company believes that the
unevaluated properties at December 31, 1998 will be substantially evaluated and
therefore subject to amortization within 12 to 24 months.
Other property and equipment are recorded at cost and are depreciated over
their estimated useful lives of five to seven years using the straight-line
method. At December 31, 1998 and 1997, furniture, fixtures and equipment, is net
of accumulated depreciation of $2.0 million and $1.5 million, respectively.
Abandonment and Dismantlement Costs
Future abandonment and dismantlement costs include costs to dismantle,
relocate and dispose of the Company's offshore production platforms, gathering
systems, wells and related structures. The Company develops estimates of its
future abandonment and dismantlement costs for each of its properties based upon
the type of production structure, depth of water, currently available
abandonment procedures and consultations with construction and engineering
consultants. The Company does not currently anticipate additional abandonment
and dismantlement costs will be incurred beyond such estimates. Such estimates
are re-evaluated by the Company's engineers at least annually.
35
<PAGE> 37
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Total estimated future abandonment and dismantlement costs associated with
the Company's developed and acquired properties were $69.1 million, $53.9
million and $41.5 million as of December 31, 1998, 1997 and 1996, respectively.
Estimated future abandonment and dismantlement costs are accrued on a
unit-of-production method based on proved reserves. The portion of future
abandonment and dismantlement costs that has been accrued is included in
accumulated depreciation, depletion and amortization and was $29.7 million,
$23.6 million and $18.0 million as of December 31, 1998, 1997 and 1996,
respectively.
Income Taxes
The Company uses the liability method of accounting for income taxes. Under
this method, deferred tax assets and liabilities are determined by applying tax
regulations existing at the end of a reporting period to the cumulative
temporary differences between the tax bases of assets and liabilities and their
reported amounts in the financial statements.
Concentration of Credit Risk
The Company maintains cash balances with several banks that frequently
exceed federally insured limits and invests its cash in investment grade
commercial and U.S. Government backed securities. The Company's joint interest
partners consist primarily of independent oil and gas producers. The Company's
oil and gas production purchasers consist primarily of independent marketers and
major gas pipeline companies. The Company performs credit evaluations of its
customers' financial condition and obtains letter of credit agreements and
parental guarantees from selected oil and gas purchase customers. The Company
has not experienced any significant losses from uncollectible accounts.
Substantially all of the Company's hedging transactions to date were carried out
in the over-the-counter market and the obligations of the counterparties have
been guaranteed by entities with at least an investment grade rating or secured
by letters of credit.
Major Customers
The Company sold oil and gas production representing more than 10% of its
oil and gas revenues for the year ended December 31, 1998, to Conoco Inc. (13%)
and Coast Energy Group (10%); for the year ended December 31, 1997, to Coast
Energy Group (12%) and Gulfmark Energy, Inc. (11%); for the year ended December
31, 1996, to Gulfmark Energy, Inc. (17%), Coast Energy Group (16%) and Superior
Natural Gas Corporation (12%). Because alternative purchasers of oil and gas are
readily available, the Company believes that the loss of any of these purchasers
would not have a material adverse effect on the Company.
2. HEDGING TRANSACTIONS:
During 1998, approximately 61% of the Company's equivalent production was
subject to hedge positions as compared to 64% in 1997.
36
<PAGE> 38
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its natural gas production for 1999 and 2000
as follows:
<TABLE>
<CAPTION>
NYMEX CONTRACT
PRICE PER MMBTU
---------------------------------------------------
COLLARS
VOLUME IN SWAPS ------------------------- FLOOR FAIR MARKET
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
- ------------------------------------------------- --------- --------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
January 1999-March 1999
Price Swap Contracts........................... 2,430 $2.45 -- -- -- $1.5 million
Collar Contracts............................... 5,600 -- $2.25-$2.58 $2.69-$3.50 -- $3.5 million
Floor Contracts................................ 1,800 -- -- -- $2.30-$2.63 $1.0 million
April 1999-June 1999
Price Swap Contracts........................... 930 $2.25 -- -- -- $0.3 million
Collar Contracts............................... 7,000 -- $2.10-$2.15 $2.25-$2.50 -- $1.4 million
July 1999-September 1999
Price Swap Contracts........................... 930 $2.24 -- -- -- $0.3 million
Collar Contracts............................... 3,750 -- $2.10 $2.40 -- $0.5 million
October 1999-December 1999
Price Swap Contracts........................... 930 $2.40 -- -- -- $0.2 million
January 2000-December 2000
Price Swap Contracts........................... 3,000 $2.31 -- -- -- $0.3 million
</TABLE>
- ---------------
(1) Fair market value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 1998.
Additionally, the Company will recognize approximately $1.4 million and
$0.2 million of gas revenue in the first and second quarters of 1999,
respectively, as a result of closing a portion of its natural gas hedge
positions in December 1998.
As of December 31, 1997, the Company had entered into commodity price
hedging contracts with respect to its natural gas production for 1998 as
follows:
<TABLE>
<CAPTION>
NYMEX CONTRACT
PRICE PER MMBTU
---------------------------------------------------
COLLARS
VOLUME IN SWAPS ------------------------- FLOOR FAIR MARKET
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(3)
- ------------------------------------------------- --------- --------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
January 1998-March 1998
Price Swap Contracts........................... 4,500 (1) $2.78 -- -- -- $2.7 million
Collar Contracts............................... 3,750 -- $2.48-$3.36 $3.21-$4.30 -- $2.4 million
Floor Contracts................................ 750 -- -- -- $2.33 $0.1 million
April 1998-June 1998
Price Swap Contracts........................... 2,500 (1) $2.27 -- -- -- $0.2 million
Collar Contracts............................... 750 -- $2.19-$2.34 $2.65-$2.89 -- $0.1 million
Floor Contracts................................ 750 -- -- -- $2.20-$2.33 $0.1 million
July 1998-September 1998
Price Swap Contracts........................... 2,250 (2) $2.26 -- -- -- $0.2 million
</TABLE>
- ---------------
(1) The Company entered into a basis swap with respect to 50% of the indicated
volume.
(2) The Company entered into a basis swap with respect to 33% of the indicated
volume.
(3) Fair market value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 1997.
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or
occasionally, the penultimate trading day of a particular contract month (the
"settlement price"). With respect to any particular swap transaction, the
counterparty is required to make a payment to the Company in the event that the
settlement price for any settlement period is less than the swap price for such
transaction, and the Company is required to make payment to the counterparty in
the event that the settlement price
37
<PAGE> 39
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
for any settlement period is greater than the swap price for such transaction.
For any particular collar transaction, the counterparty is required to make a
payment to the Company if the settlement price for any settlement period is
below the floor price for such transaction, and the Company is required to make
payment to the counterparty if the settlement price for any settlement period is
above the ceiling price of such transaction. For any particular floor
transaction, the counterparty is required to make a payment to the Company if
the settlement price for any settlement period is below the floor price for such
transaction. The Company is not required to make any payment in connection with
the settlement of a floor transaction. Except as indicated in the foregoing
tables, the Company did not have any basis swaps associated with the indicated
hedging contracts. Because substantially all of the Company's natural gas
production is sold under spot contracts that have historically correlated with
the swap price, the Company believes that it has no material basis risk with
respect to gas swaps that are not coupled with basis swaps.
As of December 31, 1998, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1999 as follows:
<TABLE>
<CAPTION>
COLLARS
-------------------------------------------
NYMEX CONTRACT
PRICE PER BBL
VOLUME IN ------------------------------ FAIR MARKET
PERIOD BBLS FLOORS CEILINGS VALUE(1)
- ------------------------------------------------------------ --------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
January 1999-March 1999..................................... 180,000 $15.00-$17.00 $17.00-$18.10 $0.7 million
April 1999-June 1999........................................ 182,000 $15.00-$17.00 $17.00-$18.70 $0.7 million
July 1999-September 1999.................................... 184,000 $15.00-$17.00 $17.00-$19.15 $0.6 million
October 1999-December 1999.................................. 92,000 $15.00 $17.00 $0.2 million
</TABLE>
- ---------------
(1) Fair market value is calculated using prices derived from NYMEX futures
contract prices existing at December 31, 1998.
As of December 31, 1997, the Company had entered into a crude oil swap
agreement for 15,000 barrels of oil production per month for the period January
1998 through June 1998, which effectively fixed the price of such production
against the NYMEX West Texas Intermediate contract at prices ranging from $20.77
to $21.52 per barrel. The fair market value of these contracts at December 31,
1997 was $0.3 million based upon prices derived from NYMEX futures contract
prices existing at December 31, 1997.
Because substantially all of the Company's oil production is sold under
spot contracts that correlate to the NYMEX West Texas Intermediate price, the
Company believes that it has no material basis risk with respect to these
transactions. The actual cash price the Company receives, however, generally is
$1.50-$2.00 per barrel less than the NYMEX West Texas Intermediate price when
adjusted for location and quality differences.
3. DEBT:
Long-term debt consisted of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1998 1997
------------- -------------
<S> <C> <C>
Senior Unsecured Debt
Bank revolving credit facility:
Prime rate based loans................................. $ -- $ 5,000
LIBOR based loans...................................... 84,000 --
-------- --------
Total bank revolving credit facility.............. 84,000 5,000
-------- --------
7.45% Senior Notes, due 2007.............................. 124,650 124,623
-------- --------
Stand alone facilities.................................... -- --
-------- --------
Long-term debt......................................... $208,650 $129,623
======== ========
</TABLE>
38
<PAGE> 40
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1998 and 1997, the interest rates under the bank revolving
credit facility for prime rate loans were 7.75% and 8.50%, respectively, and for
LIBOR based loans were 5.75% and 6.19%, respectively.
The estimated fair market value of total long-term debt at December 31,
1998 and 1997 was $203.4 million and $129.6 million, respectively. The estimated
fair value of the Company's long-term debt was based on quoted market prices.
The Company maintains its reserve-based revolving credit facility (the
"Credit Facility") with Chase Bank of Texas, National Association, as agent. As
of December 31, 1998, $84 million was outstanding under the Credit Facility. The
Credit Facility provides a $225 million revolving credit maturing on October 31,
2002. The amount available under the Credit Facility is subject to a calculated
borrowing base determined by a majority of the banks participating in the Credit
Facility, which is reduced by the aggregate principal outstanding on the
Company's senior unsecured notes (currently $125 million) (as so reduced, the
"Borrowing Base"). The Borrowing Base is currently $175 million, but no
assurances can be given that a majority of the banks will not elect to
redetermine the Borrowing Base in the future. The Company has an option, subject
to the Borrowing Base, to increase the facility to $250 million.
Borrowings under the Credit Facility bear interest, at the Company's
option, at (i) the higher of (a) the federal fund rate plus 50 basis points and
(b) the bank's prime rate or (ii) LIBOR plus a variable margin, which is based
upon the loan amount outstanding relative to the Borrowing Base and the
Company's corporate credit ratings.
The Credit Facility also provides for the payment of a commitment fee and a
standby fee. The Company paid fees of approximately $178,000, $148,000 and
$205,000 for the years ended December 31, 1998, 1997 and 1996, respectively.
The Credit Facility contains positive and negative covenants which, among
other things, require the Company to maintain a working capital ratio, as
defined, a fixed charge coverage ratio, as defined, and a minimum net worth. The
Credit Facility also limits the incurrence of additional debt, additional liens
on properties, sale of certain assets and the declaration or payment of
dividends.
On October 15, 1997, the Company issued $125 million of 7.45% Senior Notes
due 2007 ("the Notes"). The Notes were issued at 99.684% of par with a 7.45%
coupon, with interest payable on April 15 and October 15, commencing April 15,
1998. The Notes may be redeemed at any time, at the option of the Company, in
whole or in part, at a price equal to 100% of the principal amount plus accrued
and unpaid interest (if any) to the date of redemption plus a premium (if any)
relating to the then prevailing yield on United States Treasury notes with a
term equal to the remaining life of the Notes. The Notes are senior unsecured
obligations of the Company and rank pari passu in right of payment with any
existing and future senior unsecured indebtedness of the Company, including
indebtedness under its Credit Facility.
4. FEDERAL INCOME TAXES:
The components of deferred tax assets and liabilities are as follows (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1998 1997
------------ ------------
<S> <C> <C>
Deferred tax liability:
Oil and gas properties.................................... $76,455 $83,012
------- -------
Deferred tax assets:
Alternative minimum tax................................... 1,848 1,848
Net operating loss carryforwards.......................... 41,539 15,073
Other, net................................................ 1,897 2,381
------- -------
45,284 19,302
Valuation allowance......................................... -- --
------- -------
Net deferred tax liability................................ $31,171 $63,710
======= =======
</TABLE>
39
<PAGE> 41
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1998, the Company had net operating loss ("NOL")
carryforwards for federal income tax purposes of approximately $119.0 million
that may be used in future years to offset taxable income. Utilization of the
Company's NOL carryforwards are subject to annual limitations due to certain
stock ownership changes that have occurred or may occur. To the extent not
utilized, the NOL carryforwards will begin to expire in 2006.
The Company does not believe a deferred tax asset valuation is required
because all NOL carryforwards are expected to be fully utilized.
5. COMMITMENTS AND CONTINGENCIES:
The Company has entered into a non-cancellable operating lease agreement
for office space in Houston, Texas. The lease term expires in October 2005, with
two options to renew the lease for five years each. In addition, the Company
enters into various other equipment leases as part of its operations.
Future minimum lease payments required as of December 31, 1998 related to
these operating leases are as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
- ------------------------
<S> <C>
1999...................................................... $ 2,802
2000...................................................... 2,857
2001...................................................... 2,887
2002...................................................... 2,950
2003...................................................... 1,867
Thereafter................................................ 2,399
-------
Total minimum lease payments...................... $15,762
=======
</TABLE>
Rent expense for the years ended December 31, 1998, 1997 and 1996 was
$666,000, $590,000 and $537,000, respectively.
The Company has been named as a defendant in certain lawsuits arising in
the ordinary course of business. While the outcome of these lawsuits cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position, cash flows or results of
operations of the Company.
6. STOCK-BASED COMPENSATION:
The Company has several stock-based compensation plans, which are described
below. The Company applies APB Opinion No. 25 and related Interpretations in
accounting for its stock-based compensation plans.
Stock Option Plans
The Company has granted options pursuant to its 1989, 1990, 1991, 1993,
1995 and 1998 stock option plans (collectively, the "Stock Option Plans").
Options that have been granted and are outstanding generally expire 10 years
from the date of grant and become exercisable at the rate of 20% per year.
40
<PAGE> 42
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a summary of all stock option activity for 1996, 1997 and
1998:
<TABLE>
<CAPTION>
NUMBER OF WEIGHTED
SHARES AVERAGE
UNDERLYING EXERCISE
OPTIONS PRICES
---------- --------
<S> <C> <C>
Outstanding at December 31, 1995............................ 3,567,740 $ 4.76
Granted..................................................... 539,350 15.35
Exercised................................................... (598,590) 4.64
Forfeited................................................... (25,800) 9.09
--------- ------
Outstanding at December 31, 1996............................ 3,482,700 6.39
Granted..................................................... 285,000 22.16
Exercised................................................... (375,070) 5.25
Forfeited................................................... (640) 13.94
--------- ------
Outstanding at December 31, 1997............................ 3,391,990 7.84
Granted..................................................... 959,900 20.81
Exercised................................................... (296,570) 5.13
Forfeited................................................... (133,900) 21.22
--------- ------
Outstanding at December 31, 1998............................ 3,921,420 $10.76
========= ======
Exercisable at December 31, 1996............................ 2,168,770 $ 4.18
========= ======
Exercisable at December 31, 1997............................ 2,291,480 $ 4.73
========= ======
Exercisable at December 31, 1998............................ 2,442,030 $ 5.52
========= ======
</TABLE>
At December 31, 1998, the Company had an additional 771,740 options
available for grant. If granted, these additional options will be exercisable at
a price not less than the fair market value per share of the Company's common
stock on the date of grant. The weighted average fair value of options granted
during 1998, 1997 and 1996 was $8.92, $10.15 and $6.39, respectively.
The fair value of each stock option granted is estimated as of the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions for grants in 1998, 1997 and 1996: no dividend yield for all
years; expected volatility of 30.57%, 31.56% and 28.52%, respectively; risk-free
interest rates of 5.55%, 6.47% and 6.25%, respectively; and an expected option
life of 6.50 years for all years.
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1998:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
- ---------------------------------------------------------------------------- ------------------------------
WEIGHTED AVERAGE WEIGHTED WEIGHTED
RANGE OF REMAINING AVERAGE AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 3.50 to $ 5.62 2,099,930 3 years $ 3.97 2,099,930 $ 3.97
10.94 to 14.78 590,290 7 years 13.55 269,100 13.43
15.04 to 20.94 450,300 9 years 17.21 28,400 18.65
21.06 to 29.94 780,900 9 years 23.21 44,600 22.74
---------------- --------- ------- ------ --------- ------
$ 3.50 to $29.94 3,921,420 5 years $10.76 2,442,030 $ 5.52
</TABLE>
Common stock issued through the exercise of stock options results in a tax
deduction for the Company equivalent to the taxable gain recognized by the
optionee. For financial reporting purposes, the tax effect of this deduction is
accounted for as a credit to additional paid-in capital rather than as a
reduction of income tax expense. The exercise of stock options during 1998, 1997
and 1996 resulted in a tax benefit to the Company of approximately $1.9 million,
$2.3 million and $2.7 million, respectively, which was recorded as an increase
in stockholders' equity.
41
<PAGE> 43
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Employee Stock Purchase Plan
The Company established an Employee Stock Purchase Plan (the "Stock
Purchase Plan") that permits eligible employees to acquire common stock. Under
the Stock Purchase Plan, the Company is authorized to issue up to 200,000 shares
of common stock.
For each six month period beginning on January 1 or July 1 during the term
of the Stock Purchase Plan, each eligible employee has the opportunity to
purchase common stock for a purchase price equal to 85% of the lesser of the
fair market value of the common stock on (i) the first day of the period, or
(ii) the last day of the period. No employee may purchase common stock under the
Stock Purchase Plan valued at more than $25,000 for each calendar year.
Under the Stock Purchase Plan, the Company has sold 25,369 shares, 23,124
shares and 23,990 shares to employees in 1998, 1997 and 1996, respectively,
which had weighted average prices of $18.72, $17.48 and $13.56, respectively. In
accordance with APB Opinion No. 25, the Company has not recognized any
compensation cost for the Stock Purchase Plan.
The weighted average fair market value of the option to purchase stock
during 1998, 1997 and 1996 was $5.92, $7.15 and $4.99, respectively. The fair
value of each option granted under the Stock Purchase Plan is estimated on the
date of grant using the Black-Scholes option-pricing model with the following
weighted average assumptions for grants in 1998, 1997 and 1996: no dividend
yield for all years; expected volatility of 30.57%, 31.56% and 28.52%,
respectively; risk-free interest rates of 5.01%, 6.47% and 6.25%, respectively;
and an expected option life of six months for all years.
Pro Forma Net Income and Net Income Per Common Share
If the fair value based method of accounting in Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation"
("Statement No. 123") had been applied, the Company's net income and earnings
per common share for 1998, 1997 and 1996 would have approximated the pro forma
amounts below (in thousands except per share data):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Net income (loss) - as reported............................. $(57,699) $ 40,603 $ 38,494
Net income (loss) - pro forma............................... (59,275) 39,613 37,956
Basic earnings (loss) per common share - as reported........ (1.55) 1.14 1.10
Diluted earnings (loss) per common share - as reported...... (1.55) 1.07 1.03
Basic earnings (loss) per common share - pro forma.......... (1.59) 1.11 1.09
Diluted earnings (loss) per common share - pro forma........ (1.59) 1.04 1.01
</TABLE>
The effects of applying Statement No. 123 in this pro forma disclosure are
not indicative of future amounts. Statement No. 123 does not apply to awards
prior to 1995, and the Company anticipates making awards in the future under its
stock-based compensation plans.
Restricted Stock
The Company has adopted three plans pursuant to which restricted shares of
common stock may be granted. In 1998, the Company adopted the Newfield
Exploration Company 1998 Omnibus Stock Plan (the "1998 Omnibus Plan"). Under
this plan the Company may grant to employees (including an officer or director
who is also an employee) as restricted common stock all or a portion of 250,000
shares of common stock reserved under the 1998 Omnibus Plan.
Under the Newfield Exploration Company 1995 Omnibus Stock Plan (the "1995
Omnibus Plan"), the Company may grant to employees (including an officer or a
director who is also an employee) as restricted common stock all or a portion of
400,000 shares of common stock reserved under the 1995 Omnibus Plan. In 1998,
1997 and 1996 the
42
<PAGE> 44
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company issued 105,100, 35,400 and 246,000 shares, respectively, of restricted
common stock that fully vest after 9 years. Vesting may, however, be accelerated
if certain performance-based criteria are met.
Under the Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (the "Non-Employee Director Plan"), subject to a maximum
of 50,000 shares, each non-employee director who is in office immediately after
each annual meeting of stockholders of the Company shall receive a number of
restricted shares determined by dividing $30,000 by the fair market value on the
date of the annual meeting of stockholders, subject to the terms of the
Non-Employee Director Plan. The forfeiture restrictions relating to shares
issued under the amended plan will lapse 100% effective the day before the first
annual meeting of stockholders following the date of issuance of the shares,
providing the lapse conditions have been satisfied. The Company issued 8,568
shares to seven Non-Employee Directors in 1998, 10,422 shares to seven
Non-Employee Directors in 1997, and 10,000 shares to five Non-Employee Directors
in 1996.
In accordance with APB Opinion No. 25, the Company recognized unearned
compensation for the fair value of the restricted common stock in the amount of
$2.7 million for 1998, $1.0 million for 1997 and $3.6 million for 1996. This
amount is charged to stockholders' equity and recognized as compensation expense
over the applicable vesting period, in the amount of $2.0 million for 1998, $0.8
million for 1997 and $1.5 million for 1996. The weighted average price for
113,668 shares of restricted common stock issued in 1998 is $23.40. The weighted
average price for 45,822 shares of restricted common stock issued in 1997 is
$22.65. The weighted average price for 256,000 shares of restricted common stock
issued in 1996 is $14.08.
7. EMPLOYEE BENEFIT PLANS:
The Company sponsors a 401(k) Profit Sharing Plan (the "401(k) Plan") under
Section 401(k) of the Internal Revenue Code. This plan covers all employees of
the Company. The Company matches $1.00 for each $1.00 of employee deferral, with
the Company's contribution not to exceed 8% of an employee's salary, subject to
limitations imposed by the Internal Revenue Service. The Company's contributions
to the 401(k) Plan totaled $546,000, $466,000 and $371,000 for the years ended
December 31, 1998, 1997 and 1996, respectively.
The Company also sponsors the Newfield Employee 1993 Incentive Compensation
Plan (the "Plan"), which is a non-qualified plan funded by amounts equal to
revenues that would be attributable to a 1% overriding royalty interest on
acquired proved properties and a 2% overriding royalty interest from exploration
properties. Such amounts are attributable to both the Company's interest and the
interest of certain working interest owners in these properties. Amounts
available for distribution under the Plan and attributable to the overriding
royalty interests bearing against the Company are limited to 5% of the Company's
adjusted net income as defined in the Plan. The Plan is administered by the
Compensation Committee of the Board of Directors with award amounts recommended
by the Chief Executive Officer of the Company, based on the performance of the
Company and the eligible employees during the performance period. All employees
of the Company are eligible for awards if employed on both October 1 and
December 31 of the performance period. Awards may have both a current and a
deferred component of compensation. Eligible employees may elect for deferred
amounts to be paid in common stock instead of cash. If the eligible employee
elects for a deferred amount to be paid in common stock, the number of shares of
common stock to be awarded is determined by using the fair market value of
common stock on the date of the award. Total expenses under the Plan for the
years ended December 31, 1998, 1997 and 1996 were $1.9 million, $5.3 million and
$4.9 million, respectively.
During 1997, the Company implemented a highly compensated employee Deferred
Compensation Plan (the "Deferred Plan"). This non-qualified plan allows an
eligible employee to defer a portion of the employee's salary or bonus on an
annual basis. The Company matches $1.00 for each $1.00 of employee deferral,
with the Company's contribution not to exceed 8% of an employee's salary,
subject to limitations imposed by the Deferred Plan. The Company's contribution
is reduced by the amount of contribution made by the Company to the 401(k) Plan
for each participant. The Company's contributions to the Deferred Plan totaled
$30,000 and $22,000 for the years ended December 31, 1998 and 1997,
respectively.
43
<PAGE> 45
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. RELATED PARTY TRANSACTIONS:
The 401(k) Plan invests in several mutual funds (the "Warburg Funds")
affiliated with Warburg, Pincus & Co. Warburg, Pincus & Co. is general partner
of Warburg, Pincus Investors, L.P., a significant stockholder of the Company
which is represented on the Company's Board of Directors. The amount invested in
the Warburg Funds at any time depends upon the elections made by the
participants in the 401(k) Plan. The Company believes that the 401(k) Plan
invests on the same basis in terms of rates and fees as are offered generally to
similar employee investment vehicles. The aggregate amount of the 401(k) Plan's
assets invested in Warburg Funds were approximately $2.0 million and $1.6
million as of December 31, 1998 and 1997, respectively.
9. SUPPLEMENTAL CASH FLOW INFORMATION:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash payments:
Interest payments (net of interest capitalized of $4,369,
$3,481 and $1,508 during 1998, 1997 and 1996,
respectively).......................................... $ 7,478 $ 1,196 $ 363
Income tax payments....................................... -- -- --
Transactions excluded from the statement of cash flows:
Increase (decrease) in accrued capital expenditures....... $ (7,059) $10,850 $ 5,062
Other..................................................... (23) (50) (86)
</TABLE>
10. SUBSEQUENT EVENTS:
On February 12, 1999, the Company adopted a stockholder rights plan. The
plan is designed to ensure that all Newfield stockholders receive fair and equal
treatment in the event of a proposed takeover of the Company. It includes
safeguards against partial or two-tiered tender offers, squeeze-out mergers and
other abusive takeover tactics.
The plan provides for the issuance of one right for each outstanding share
of the Company's common stock. The rights will become exercisable only if a
person or group acquires 20% or more of the Company's outstanding voting stock
or announces a tender or exchange offer that would result in ownership of 20% or
more of the Company's voting stock.
Each right will entitle the holder to buy one one-thousandth (1/1000) of a
share of a new series of junior participating preferred stock at an exercise
price of $85 per right, subject to antidilution adjustments. Each one one-
thousandth of a share of this new preferred stock has the dividend and voting
rights of, and is designed to be substantially equivalent to, one share of
common stock. The Company's Board of Directors may, at its option, redeem all
rights for $0.01 per right at any time prior to the acquisition of 20% or more
of the Company's stock by a person or group.
If a person or group acquires 20% or more of the Company's outstanding
voting stock, each right will entitle holders, other than the acquiring party,
to purchase common stock of the Company having a market value of $170 for a
purchase price of $85, subject to antidilution adjustments.
The plan also includes an exchange option. If a person or group acquires
20% or more, but less than 50% of the outstanding voting stock, the Board of
Directors may at its option exchange the rights in whole or in part for shares
of common stock of the Company. Under this option, the Company would issue one
share of common stock, or one one-thousandth of a share of new preferred stock,
for each two shares of common stock for which a right is then exercisable. This
exchange would not apply to rights held by the person or group holding 20% or
more of the Company's voting stock.
If, after the rights have become exercisable, the Company merges or
otherwise combines with another entity, or sells assets constituting more than
50% of its assets or producing more than 50% of its earning power or cash flow,
44
<PAGE> 46
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
each right then outstanding will entitle its holder to purchase for $85, subject
to antidilution adjustments, a number of the acquiring party's common shares
having a market value of twice that amount.
This plan will not prevent, nor is it intended to prevent, a takeover of
the Company. Since the rights may be redeemed by the Board under certain
circumstances, they should not interfere with any merger or other business
combination approved by the Board. The issuance of the rights does not in any
way diminish the financial strength of the Company or interfere with its
business plans. The issuance of the rights has no dilutive effect, will not
affect reported earnings per share and will not change the way the common stock
of the Company is currently traded.
11. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
The results of operations by quarter for the years ended December 31, 1998
and 1997 are as follows (in thousands, except per share amounts):
<TABLE>
<CAPTION>
1998 QUARTER ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- --------- ------------ -----------
<S> <C> <C> <C> <C>
Oil and gas revenues........................ $ 49,982 $ 49,902 $ 45,296 $ 50,505
Income from operations...................... 11,696 7,785 4,377 (103,690)
Net income (loss)........................... 6,712 3,772 850 (69,033)
Basic earnings (loss) per common share...... $ 0.19 $ 0.10 $ 0.02 $ (1.71)
Diluted earnings (loss) per common share.... $ 0.18 $ 0.10 $ 0.02 $ (1.71)
</TABLE>
<TABLE>
<CAPTION>
1997 QUARTER ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- --------- ------------ -----------
<S> <C> <C> <C> <C>
Oil and gas revenues........................ $ 46,927 $ 42,345 $ 49,863 $ 60,264
Income from operations...................... 18,207 12,252 14,223 19,885
Net income.................................. 11,887 7,773 8,715 12,228
Basic earnings per common share............. $ 0.34 $ 0.22 $ 0.24 $ 0.34
Diluted earnings per common share........... $ 0.31 $ 0.21 $ 0.23 $ 0.32
</TABLE>
45
<PAGE> 47
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate that 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 are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
No major discovery or other favorable or adverse event subsequent to
December 31, 1998 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
46
<PAGE> 48
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES
The following table sets forth the Company's net proved reserves (at 15.025
pounds per square inch absolute), including the changes therein, and proved
developed reserves (all within the United States) at the end of each of the
three years in the period ended December 31, 1998, as estimated by the Company's
petroleum engineering staff:
<TABLE>
<CAPTION>
OIL, CONDENSATE
AND NATURAL NATURAL
GAS LIQUIDS GAS
(MBBLS) (MMCF)
--------------- -------
<S> <C> <C>
Proved developed and undeveloped reserves:
December 31, 1995........................................... 9,633 203,580
Revisions of previous estimates........................... 850 (1,829)
Extensions, discoveries and other additions............... 3,479 68,011
Purchases of properties................................... 2,306 13,063
Sales of properties....................................... (51) (117)
Production................................................ (2,558) (41,323)
------ -------
December 31, 1996........................................... 13,659 241,385
Revisions of previous estimates........................... 6 3,014
Extensions, discoveries and other additions............... 3,716 83,783
Purchases of properties................................... 2,426 66,594
Sales of properties....................................... (76) (3,790)
Production................................................ (3,424) (53,505)
------ -------
December 31, 1997........................................... 16,307 337,481
Revisions of previous estimates........................... (246) 1,981
Extensions, discoveries and other additions............... 1,635 83,777
Purchases of properties................................... 1,118 65,672
Sales of properties....................................... -- --
Production................................................ (3,643) (66,634)
------ -------
December 31, 1998........................................... 15,171 422,277
====== =======
Proved developed reserves:
December 31, 1995......................................... 8,292 154,726
December 31, 1996......................................... 11,820 199,452
December 31, 1997......................................... 15,712 252,018
December 31, 1998......................................... 14,647 388,040
</TABLE>
47
<PAGE> 49
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
Capitalized costs for oil and gas producing activities consist of the
following at the end of each of the three years in the period ended December 31,
1998 (in thousands):
<TABLE>
<CAPTION>
OTHER
DOMESTIC CHINA FOREIGN TOTAL
--------- ------- ------- ---------
<S> <C> <C> <C> <C>
DECEMBER 31, 1998
Proved Properties.......................................... $ 962,421 $ -- $ -- $ 962,421
Unproved Properties........................................ 21,044 7,934 1,230 30,208
--------- ------- ------- ---------
983,465 7,934 1,230 992,629
Accumulated depreciation, depletion and amortization....... (414,206) -- -- (414,206)
--------- ------- ------- ---------
Net capitalized cost....................................... $ 569,259 $ 7,934 $ 1,230 $ 578,423
========= ======= ======= =========
DECEMBER 31, 1997
Proved Properties.......................................... $ 718,915 $ -- $ -- $ 718,915
Unproved Properties........................................ 48,820 7,424 426 56,670
--------- ------- ------- ---------
767,735 7,424 426 775,585
Accumulated depreciation, depletion and amortization....... (291,631) -- -- (291,631)
--------- ------- ------- ---------
Net capitalized cost....................................... $ 476,104 $ 7,424 $ 426 $ 483,954
========= ======= ======= =========
DECEMBER 31, 1996
Proved Properties.......................................... $ 501,328 $ -- $ -- $ 501,328
Unproved Properties........................................ 25,352 -- -- 25,352
--------- ------- ------- ---------
526,680 -- -- 526,680
Accumulated depreciation, depletion and amortization....... (198,065) -- -- (198,065)
--------- ------- ------- ---------
Net capitalized cost....................................... $ 328,615 $ -- $ -- $ 328,615
========= ======= ======= =========
</TABLE>
48
<PAGE> 50
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
Costs incurred for oil and gas property acquisition, exploration and
development activities for each of the three years in the period ended December
31, 1998 are as follows (in thousands):
<TABLE>
<CAPTION>
OTHER
DOMESTIC CHINA FOREIGN TOTAL
-------- -------- ------- --------
<S> <C> <C> <C> <C>
1998
Property acquisition:
Unproved*................................................. $ 3,400 $ -- $ -- $ 3,400
Proved.................................................... 86,219 -- -- 86,219
Exploration................................................. 63,802 510 1,002 65,314
Development................................................. 155,839 -- -- 155,839
-------- -------- ------- --------
Total costs incurred.............................. $309,260 $ 510 $ 1,002 $310,772
======== ======== ======= ========
1997
Property acquisition:
Unproved*................................................. $ 31,541 $ 6,770 $ 426 $ 38,737
Proved.................................................... 30,368 -- -- 30,368
Exploration................................................. 61,825 4,908 -- 66,733
Development................................................. 117,321 -- -- 117,321
-------- -------- ------- --------
Total costs incurred.............................. $241,055 $ 11,678 $ 426 $253,159
======== ======== ======= ========
1996
Property acquisition:
Unproved*................................................. $ 5,670 $ -- $ -- $ 5,670
Proved.................................................... 28,480 -- -- 28,480
Exploration................................................. 49,337 -- -- 49,337
Development................................................. 80,336 -- -- 80,336
-------- -------- ------- --------
Total costs incurred.............................. $163,823 $ -- $ -- $163,823
======== ======== ======= ========
</TABLE>
- ---------------
* These amounts represent costs incurred by the Company and excluded from the
amortization base until proved reserves are established or impairment is
determined.
49
<PAGE> 51
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures
about Oil and Gas Producing Activities" ("FAS 69") and based on natural gas and
crude oil reserve and production volumes estimated by the Company's petroleum
engineering staff. It may be useful for certain comparative purposes, but should
not be solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should the
Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.
The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and gas revenues; and (4)
future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying period-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of period-end proved reserves.
Future cash inflows at December 31, 1998 do not reflect the impact of future
production that is subject to open hedge positions (see Note 2). Future cash
inflows were reduced by estimated future development, abandonment and production
costs based on period-end costs in order to arrive at net cash flow before tax.
Future income tax expense has been computed by applying period-end statutory tax
rates to aggregate future pre-tax net cash flows, reduced by the tax basis of
the properties involved and tax carryforwards. Use of a 10% discount rate is
required by FAS 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
50
<PAGE> 52
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves (all within the United States) is as follows (in
thousands):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows......................................... $1,047,290 $1,150,023 $1,312,815
Less related future:
Production costs.......................................... (203,717) (159,619) (113,937)
Development and abandonment costs......................... (162,005) (170,537) (107,205)
---------- ---------- ----------
Future net cash flows before income taxes................... 681,568 819,867 1,091,673
10% annual discount for estimating timing of cash flows..... (131,750) (165,198) (231,856)
---------- ---------- ----------
Standardized measure of discounted future net cash flows
before income taxes....................................... 549,818 654,669 859,817
Future income tax expense, net of 10% annual discount....... (98,662) (151,721) (247,889)
---------- ---------- ----------
Standardized measure of discounted future net cash flows.... $ 451,156 $ 502,948 $ 611,928
========== ========== ==========
</TABLE>
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves (all within the United
States) is as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
Beginning of the period..................................... $ 502,948 $ 611,928 $ 276,326
---------- ---------- ----------
Revisions of previous estimates:
Changes in prices and costs............................... (226,749) (356,858) 254,227
Changes in quantities..................................... 662 5,535 9,544
Changes in future development costs....................... 5,401 (7,464) --
Development costs incurred during the period................ 55,153 35,810 24,895
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs..... 117,837 136,977 229,314
Purchases of reserves in place.............................. 48,889 101,266 55,910
Accretion of discount....................................... 65,467 85,982 36,488
Sales of oil and gas, net of production costs............... (160,340) (175,091) (132,310)
Net change in income taxes.................................. 53,059 96,168 (159,336)
Production timing and other................................. (11,171) (31,305) 16,870
---------- ---------- ----------
Net increase (decrease)..................................... (51,792) (108,980) 335,602
---------- ---------- ----------
End of the period........................................... $ 451,156 $ 502,948 $ 611,928
========== ========== ==========
</TABLE>
51
<PAGE> 53
CORPORATE INFORMATION
DIRECTORS
Philip J. Burguieres (**)(***)(55)
Chairman Emeritus
Weatherford International, Inc.
Charles W. Duncan, Jr. (*)(***)(72)
Private Investor
Duncan Interests
Joe B. Foster (64)
Chairman, President and
Chief Executive Officer
Newfield Exploration Company
Dennis R. Hendrix (*)(***)(59)
Retired Chairman
PanEnergy Corp.
Director
Duke Energy Corporation
Terry Huffington (*)(**)(44)
Chairman and President
Huffco Group, Inc.
Howard H. Newman (*)(***)(51)
Managing Director
E.M. Warburg, Pincus & Co., LLC
Thomas G. Ricks (*)(**)(45)
President and Chief Executive Officer
The University of Texas Investment
Management Company
John C. Sawhill (*)(**)(62)
President and Chief Executive Officer
The Nature Conservancy
C. E. (Chuck) Shultz (**)(***)(59)
Chairman and Chief Executive Officer
Dauntless Energy, Inc.
Robert W. Waldrup (54)
Vice President - Operations
Newfield Exploration Company
(*) Member of the Compensation
Committee
(**) Member of the Audit Committee
(***) Member of the Management
Development Committee
OFFICERS
Joe B. Foster (64)
Chairman, President and
Chief Executive Officer
Robert W. Waldrup (54)
Vice President - Operations
David A. Trice (50)
Vice President - Finance and International
Terry W. Rathert (46)
Vice President - Planning and
Administration and Secretary
David F. Schaible (38)
Vice President - Acquisitions and
Development
Elliott Pew (44)
Vice President - Exploration
William D. Schneider (47)
Vice President - International Exploration
Ronald P. Lege (54)
Controller and Assistant Secretary
C. William Austin (46)
Legal Counsel and Assistant Secretary
James P. Ulm, II (36)
Treasurer
MARKET INFORMATION
The Company's common stock is traded on the NYSE
under the symbol NFX. The stock began trading
November 12, 1993. The range of high and low
quarterly sales prices for 1997 and 1998, as reported
by the NYSE, are set forth below:
<TABLE>
<CAPTION>
High Low
---- ---
<S> <C> <C>
1997
First Quarter 28 18 1/2
Second Quarter 23 7/8 16 7/8
Third Quarter 28 1/8 19 15/16
Fourth Quarter 33 20
1998
First Quarter 27 11/16 19 9/16
Second Quarter 26 3/8 17 13/16
Third Quarter 24 7/8 15 7/16
Fourth Quarter 26 7/16 16 5/8
</TABLE>
TRANSFER AGENT
For more information regarding change of address
or other matters concerning your stockholder account,
please contact the transfer agent directly at:
ChaseMellon Shareholders Services L.L.C.
Overpeck Centre
85 Challenger Road
Ridgefield Park, NJ 07660
(800) 635-9270
www.chasemellon.com
On December 31, 1998, the closing sale price for the
Company's stock was $20 7/8 per share. Management
believes after inquiry, that the number of beneficial
owners of the Company's common stock is in excess
of 2,000.
ANNUAL MEETING
The Annual Meeting of Stockholders of Newfield
Exploration Company will be held May 5, 1999, at
11:00 a.m. at the Hotel Sofitel, 425 North Sam
Houston Parkway East, Houston, Texas.
CORPORATE ADDRESS
363 North Sam Houston Parkway East
Suite 2020
Houston, Texas 77060
(281) 847-6000
www.newfld.com
OUTSIDE LEGAL COUNSEL
Vinson & Elkins L.L.P.
Houston, Texas
AUDITORS
PricewaterhouseCoopers LLP
Houston, Texas
CREDITS
Newfield employees Chris Clark, Andy Lundy, Chris
Mabie and Mike Minarovic contributed photographs
to this annual report.
FORM 10-K
Stockholders may obtain without charge a copy of
Newfield's Form 10-K report as filed with the Securities
and Exchange Commission. For copies or answers to
questions about Newfield Exploration Company, please
contact Stockholder Relations at the corporate address.
<PAGE> 54
NEWFIELD
[NEWFIELD LOGO]
EXPLORATION COMPANY
363 N. SAM HOUSTON PARKWAY E.
SUITE 2020
HOUSTON, TEXAS 77060
TELEPHONE: 281-847-6000
FAX: 281-847-6006
www.newfld.com
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference into the registration
statements of Newfield Exploration Company (the "Company") on Form S-8
(Registration No.s 33-72848, 33-79826, 33-92182 and 333-59383) and on
Form S-3 (Registration No.s 333-32587 and 333-59391) of our report dated
February 12, 1999 on our audits of the financial statements of Newfield
Exploration Company as of December 31, 1998 and 1997, and for each of the
three years in the period ended December 31, 1998, which report is
incorporated by reference in the Company's Form 10-K for the year
ended December 31, 1998.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 1, 1999
<PAGE> 1
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the use of our name in "Item 2. Properties" of the Annual
Report on Form 10-K of Newfield Exploration Company (the "Company") for the year
ended December 31, 1998 (the "Form 10-K"), and the incorporation by reference of
the Form 10-K into the Company's Registration Statements on Form S-8
(Registration No. 33-72848, No. 33-79826, No 33-92182 and No. 333-59383) and on
Form S-3 (Registration No. 333-32587 and No. 333-59391).
/s/ RYDER SCOTT COMPANY
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
March 1, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NEWFIELD
EXPLORATION COMPANY'S CONSOLIDATED BALANCE SHEET AT DECEMBER 31, 1998 AND
CONSOLIDATED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1998, THAT ARE
CONTAINED IN ITS FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1998. THE SCHEDULE
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 92
<SECURITIES> 0
<RECEIVABLES> 43,095
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 45,269
<PP&E> 996,866
<DEPRECIATION> 416,235
<TOTAL-ASSETS> 629,311
<CURRENT-LIABILITIES> 54,075
<BONDS> 208,650
0
0
<COMMON> 251,046
<OTHER-SE> 72,902
<TOTAL-LIABILITY-AND-EQUITY> 629,311
<SALES> 195,685
<TOTAL-REVENUES> 195,685
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 158,492
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 9,508
<INCOME-PRETAX> (88,376)
<INCOME-TAX> (30,677)
<INCOME-CONTINUING> (57,699)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (57,699)
<EPS-PRIMARY> (1.55)
<EPS-DILUTED> (1.55)
</TABLE>
