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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, 1996
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)
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)
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 $.01 Per Share New York Stock Exchange
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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 $359,699,000 as of February 28, 1997 (based on
the last sale price of such stock as quoted on the New York Stock Exchange).
As of February 28, 1997 there were 35,235,927 shares of the Registrant's
Common Stock, par value $.01 per share, outstanding.
Documents incorporated by reference: 1996 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 1, 1997, which is incorporated into
Part III of this Form 10-K.
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TABLE OF CONTENTS
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PAGE
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PART I
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Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . .11
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . .11
Item 4A. Executive Officers of the Registrant . . . . . . . . . . . . . .11
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . .13
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . .13
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . .13
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . .13
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . . .14
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . .14
Item 12. Security Ownership of Certain Beneficial Owners and Management .14
Item 13. Certain Relationships and Related Transactions . . . . . . . . .14
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. .14
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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, 1996 the Company
had proved reserves of 323.3 billion cubic feet equivalent ("Bcfe," determined
using the ratio of six thousand cubic feet of natural gas ("Mcf") to one barrel
("Bbl") of crude oil, condensate or natural gas liquids) consisting of 13.7
million Bbls ("MMBbls") of oil and condensate and 241.4 billion cubic feet
("Bcf") of natural gas. Approximately 75% of the Company's proved reserves are
natural gas and approximately 84% are 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."
Newfield's strategy is to continue to expand its reserve base and
increase its cash flow through exploration, acquisitions of proved properties
and development of its properties. The Company emphasizes the following
elements in implementing this strategy:
o Reserve growth through high potential exploratory drilling
o Balance between exploration and acquisitions of proved properties
o Geographic focus in the Gulf of Mexico
o Control of operations and costs
o Use of 3-D seismic and other advanced technology
o Equity ownership and other incentives to retain and attract
employees
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 believes there are many other advantages to operating in the
Gulf of Mexico. The Company's management and other technical personnel have
extensive experience in the Gulf of Mexico, and the Company's geographic focus
assists it in controlling operating and administrative costs. There is also a
significant amount of seismic and other geologic data available at reasonable
cost. The shallow waters of the Gulf of Mexico have a substantial existing
infrastructure, including gathering systems, platforms, pipelines and drilling
and service companies, which facilitates cost effective operations and the
timely development of discoveries.
An important part of the Company's strategy is to maintain geographic
focus. While the Company does not have any current plans to expand its primary
operations beyond the Gulf Coast Basin, it may consider the acquisition of a
group of properties outside this area in the future. The Company expects that
any significant acquisition outside the Gulf of Mexico would, however, be made
with a view to developing a similar geographic focus.
OPERATIONS
The Company's exploration and acquisition activities complement each
other. Properties acquired by the Company often hold exploration potential and
can increase the Company's presence in an area, creating the infrastructure
that can make otherwise uneconomic exploratory prospects attractive.
Information gathered while evaluating production on acquisition candidates and
adjacent acreage is used, as appropriate, in the Company's exploration efforts.
Conversely, a successful exploration prospect may reveal similar untested
reserve potential on a proved property believed to be marginal by its owner,
making its purchase attractive.
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EXPLORATION ACTIVITIES. The Company maintains an active exploration
program. During 1996 the Company invested $48.5 million for exploration costs,
including seismic data, leasehold and exploration test well drilling. 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, 1996,
the Company drilled 72 exploratory wells at a cost to drill and evaluate of
$102.3 million. These wells have resulted in the discovery of proved reserves
of 5.7 MMBbls of oil and condensate and 153.0 Bcf of natural gas. All but
eleven of these wells were operated by the Company. Fifty-one of the wells
operated by the Company were drilled under turnkey drilling contracts, which
are fixed rate contracts pursuant to which the drilling contractor is generally
responsible for making critical operating decisions and bears the risk of loss
for unbudgeted contingencies.
The Company is constantly in the process of reviewing or negotiating a
number of potential farm-in opportunities. The Company is also involved on a
regular basis in exploration prospecting on open acreage and participates in
federal and state lease sales to acquire open acreage as drillable prospects
are developed. Presently, the Company has 14 prospects on acreage it controls
and in which it owns a majority interest and has three potential prospects on
farm-in acreage.
ACQUISITION ACTIVITIES. The Company actively pursues the acquisition
of proved oil and gas properties in the Gulf of Mexico, particularly properties
with undeveloped or unexploited reserve potential in order to enhance returns.
The Company looks for properties that it can operate 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 workovers, recompletions and development drilling on many
of its properties to increase production and cash flow, develop proved
undeveloped reserves and evaluate probable reserves.
The Company pursues a multi-discipline team approach for evaluating
acquisition opportunities. Acquisition candidates 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.
CONTROL OF OPERATIONS AND COSTS. The Company prefers exploration
prospects and property acquisitions that allow it to operate the properties in
order to manage production performance closely and to control operating
expenses and the timing and amount of capital expenditures. Properties
operated by the Company accounted for 89% of its total equivalent production
for 1996. The Company operates 59 platforms and 18 oil or gas pipelines,
excluding field gathering lines. The geographic focus of the Company's
operations allows it to manage a large asset base with a relatively small
number of employees. The Company uses independent contractors for much of its
field operations activities and administrative work. This base of operations
enables the Company to add successful exploratory wells and proved property
acquisitions at relatively low incremental costs. The Company believes that
its low cost structure and existing infrastructure permit it to drill
exploratory prospects and acquire properties that other oil and gas companies
may consider economically unattractive.
TECHNOLOGY. Newfield uses advanced technology in its exploration
and development activities in order to reduce its risks and lower its costs.
The Company currently holds licenses to more than 75,000 miles of recent
vintage conventional seismic data in the Central Gulf of Mexico and 100 3-D
seismic surveys including coverage of 31 producing fields it operates, and owns
a library containing logs on more than 4,000 wells drilled in the Company's
focus area. In addition, the Company has licenses to 300,000 miles of regional
2-D seismic coverage across the Gulf of Mexico.
The Company evaluates many of its exploratory prospects with 3-D
seismic surveys prior to drilling. The availability of 3-D coverage for the
shallow waters of the Gulf of Mexico at a reasonable cost makes its use in
exploration attractive from a risk management perspective. The Company has
also made a significant investment in computer-aided exploration ("CAEX")
through the licensing of interactive workstations and software and the training
of professionals. The use of 3-D seismic and CAEX technology provides the
Company with substantially more accurate and comprehensive geological data for
the evaluation of drilling prospects than 2-D seismic and traditional
evaluation methods. The Company believes that its use of 3-D seismic and CAEX
technology provides it with an advantage over those companies that do not
regularly utilize similar technology by increasing the Company's likelihood of
success.
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MANAGEMENT AND EMPLOYEES. Newfield's management and 30 technical
personnel have extensive experience in the Gulf of Mexico. In order to retain
and attract its employees, the Company provides incentives through equity
ownership and other benefit plans. As of December 31, 1996, the Company's
employees owned or had options to acquire an aggregate of 13% of the Company's
outstanding Common Stock, par value $.01 per share ("Common Stock"), on a fully
diluted basis.
MARKETING - HEDGE TRANSACTIONS
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. The Company has one market-
sensitive long-term contract (accounting for approximately 5% of gas sales
during recent months) under which the buyer has certain obligations to take
natural gas. The majority of the Company's natural gas production, however, is
sold to a variety of purchasers under short-term (less than 12 months)
contracts or 30-day spot gas purchase contracts. During 1996, Coast Energy
Group and Superior Natural Gas Corporation 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 1996, Gulfmark Energy, Inc. and Northridge Energy Marketing each
purchased in excess of 10% of the oil sold by the Company for its own account.
Based upon the current demand for oil and gas, 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 financial statements.
From time to time, the Company has utilized 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.
During 1996, approximately 54% of the Company's equivalent production
was subject to hedge positions. The Company has also entered into hedging
transactions with respect to a portion of its estimated production for 1997.
The Company continues to evaluate whether to enter into additional hedging
transactions for 1997 and future years. In addition, the Company may determine
from time to time to terminate its then existing hedging positions. The
following is a summary of the Company's natural gas hedge positions as of
January 1, 1997.
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MONTHLY
VOLUME WEIGHTED AVERAGE
PERIOD IN BCF SALES POINT PRICE PER MCF (1)
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COLLAR
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SWAP FLOOR CEILING
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January 1997 - March 1997
Price Swap Contracts 1.30 $ 2.36 -- --
Cashless Collar Contracts 1.25 -- $ 2.22 $ 2.67
Cashless Collar Contracts 1.30 -- $ 2.76 $ 3.25
April 1997 - June 1997
Price Swap Contracts 0.80 $ 2.08 -- --
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(1) Price per Mcf is based upon the average energy content of the
Company's gas production for the twelve months ended December 31, 1996.
These gas swaps are settled based on reported sales prices of natural
gas delivered into those pipelines at the physical locations where the
Company sells its production, (the "Sales Point Price"). With respect to any
particular swap transaction, the counterparty is required to make a payment
to the Company in the event that the average Sales Point 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
average Sales Point 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
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if the average Sales Point Price for the reference period is below the floor
price for such transaction, and the Company is required to make payment to the
counterparty if the average Sales Point Price for the reference period is above
the ceiling price for such transaction. Because substantially all of the
Company's natural gas production is sold under spot contracts that reference
the Sales Point Price, the Company has no basis risk with respect to these
transactions.
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 the
locations of its leasehold acreage, 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.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, and
636-B (collectively, "Order No. 636"), which require interstate pipelines to
provide transportation separate, or "unbundled," from the pipelines' sales of
gas. Also, Order No. 636 requires pipelines to provide open-access
transportation on a basis that is equal for all gas supplies. Although Order
No. 636 does not directly regulate the Company's activities, the FERC has
stated that it intends for Order No. 636 to foster increased competition within
all phases of the natural gas industry. It is unclear what impact, if any,
increased competition within the natural gas industry under Order No. 636 will
have on the Company's activities. Although Order No. 636 could provide the
Company with additional market access and more fairly applied transportation
service rates, Order No. 636 could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. The FERC has issued final orders on all Order No. 636 pipeline
restructuring proceedings. The United States Court of Appeals for the District
of Columbia Circuit ("the D.C. Circuit") has generally affirmed Order No. 636
and remanded certain issues for further explanation or clarification. The
issues remanded for further action do not appear to materially affect the
Company. Numerous petitions for review of the individual pipeline
restructuring orders are currently pending in that court. Although it is
difficult to predict when all appeals of pipeline restructuring orders will be
completed or their impact on the Company, the Company does not believe that it
will be affected by the restructuring rule and orders any differently than
other natural gas producers and marketers with which it competes.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price that shippers can charge for their released capacity. In addition,
in 1995, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. In January 1996,
the FERC issued a policy statement and a request for comments concerning
alternatives to its traditional cost-of-service ratemaking methodology. A
number of pipelines have obtained FERC authorization to charge negotiated rates
as one such alternative. While any additional FERC action on these matters
would affect the Company only indirectly, any new rules and policy statements
may have the effect of enhancing competition in the natural gas markets by,
among other things, encouraging non-producer natural gas marketers to engage in
certain purchase and sale transactions. The Company cannot predict what action
the FERC will take on these matters, nor can it accurately predict whether the
FERC's actions will achieve the goal of increasing competition in markets in
which the Company's natural gas is sold. However, the Company does not believe
that it will be affected by any action taken materially differently than other
natural gas producers with which it competes.
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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.
Commencing in May 1994, the FERC issued a series of orders in
individual cases that delineate its new gathering policy. Among other matters,
the FERC slightly narrowed its statutory tests for establishing gathering
status and reaffirmed that, except in situations in which the gatherer acts in
concert with an interstate pipeline affiliate to frustrate the FERC's
transportation policies, it does not generally have jurisdiction over natural
gas gathering facilities and services, and that such facilities and services
located in state jurisdictions are properly regulated by state authorities.
This FERC action may further encourage regulatory scrutiny of natural gas
gathering by state agencies. In addition, the FERC has approved several
transfers by interstate pipelines of gathering facilities to unregulated
independent or affiliated gathering companies, subject to the transferee
providing service for two years from the date of transfer to the pipeline's
existing customers pursuant to a default contract or pursuant to mutually
agreeable terms. In August 1996, the D.C. Circuit largely upheld the FERC's
new gathering policy, but remanded the FERC's default contract condition. The
FERC has not yet issued an order on remand. The Company does not believe that
it will be affected by the FERC's new gathering policy any differently than
other producers, gatherers and marketers with which it competes.
The new gathering policy thus far announced by the FERC in these
orders does not address its jurisdiction over pipelines operating on or across
the OCS pursuant to the OCSLA. If the FERC were to apply Order No. 509 to
gatherers in the OCS, eliminate the exemption of gathering lines, and redefine
its jurisdiction over gathering lines, then these acts could result in a
reduction in available pipeline space for existing shippers in the Gulf of
Mexico, such as the Company.
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 United
States Department of the Interior Minerals Management Service (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 proposed additional safety-related regulations
concerning the design and operating procedures for OCS production platforms and
pipelines. These proposed regulations were withdrawn pending further
discussions among interested federal agencies. 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 and operations.
In addition, the MMS is conducting an inquiry into certain contract
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 impact on its financial condition, liquidity
or results of operations.
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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 natural gas produced from federal leases. The principal
feature in the amendments, as proposed, would establish an alternative
market-index based method to calculate royalties on certain natural gas
production sold to affiliates or pursuant to non-arm's-length sales contracts.
The MMS has proposed this rulemaking to facilitate royalty valuation in light
of changes in the gas marketing environment. 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 impact on its financial
condition, liquidity or results of operations.
The MMS has recently 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 impact on its financial condition, liquidity
or results of operations.
STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION. The Company
owns interests in properties located 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 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.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil,
condensate and gas liquids by the Company are not currently regulated and are
made at market prices. Effective as of January 1, 1995, the FERC implemented
regulations establishing an indexing system for transportation rates for oil
that could increase the cost of transporting oil to the purchaser. The Company
is not able to predict what effect, if any, this order will have on it, but
other factors being equal, it may tend to increase transportation costs or
reduce wellhead prices for crude oil.
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. 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 a facility or vessel, 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. Few defenses
exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party,
including proof of financial responsibility to cover at least some costs in a
potential spill. Under recent amendments to the OPA, owners and operators of
offshore oil and gas facilities are required to demonstrate $35 million in
financial responsibility to cover environmental cleanup and restoration costs
that could be incurred by governmental entities in connection with an oil
spill, unless a formal risk assessment conducted by the MMS indicates that a
higher amount (up to $150 million) should be required. Although the MMS has
not yet promulgated rules for implementation of the recently adopted financial
responsibility requirements, the Company expects that the MMS will allow
financial responsibility to be demonstrated through insurance, guaranty,
indemnity, surety bond, letter of credit, qualification as a self-insurer, or a
combination of the foregoing. While the Company cannot predict the final form
of any financial responsibility rule that may be adopted pursuant to the OPA,
the
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impact of the rule should not be any more adverse to the Company than it will
be to other similarly situated or less capitalized owners or operators in the
Gulf of Mexico.
The OPA also imposes other requirements, such as the preparation of an
oil spill contingency plan. The Company has such a plan in place. 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, 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. Initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company.
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 impact
on the Company.
OPERATING HAZARDS AND INSURANCE
The oil and gas business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, casing
collapse, abnormally pressured formations and environmental hazards such as oil
spills, gas leaks, ruptures and discharges of toxic gases, the occurrence of
any of which could result in substantial losses to the Company due to injury or
loss of life, severe damage to or destruction of property, natural resources
and equipment, pollution or other environmental damage, clean-up
responsibilities, regulatory investigation and penalties and suspension of
operations. In addition to the foregoing, substantially all of the Company's
operations are currently offshore and subject to the additional hazards of
marine operations, such as capsizing of vessels, collision and adverse weather
and sea conditions.
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 condition and
operations.
-7-
<PAGE> 10
EMPLOYEES
At February 28, 1997 the Company had 66 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.
ITEM 2. PROPERTIES
Substantially all of the Company's proved properties are located in
the federal waters of the Gulf of Mexico, primarily offshore Louisiana. The
Company's reserves are concentrated, with the eight largest properties
accounting for approximately 60% of the Company's equivalent proved reserves as
of December 31, 1996, but no single property held more than 15% of the
Company's equivalent proved reserves as of such date. The Company is the
operator of properties which accounted for 89% of its net production in 1996.
OIL AND GAS RESERVES
The following table sets forth estimated net proved oil and gas
reserves of the Company and the present value of estimated future pre-tax net
cash flows related to such reserves as of December 31, 1996. 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 net cash flows was prepared using constant
prices as of the calculation date, discounted at 10% per annum on a pre-tax
basis.
<TABLE>
<CAPTION>
PROVED RESERVES
----------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
<S> <C> <C> <C>
Oil and condensate (MBbls) . . . . . . . . . . . . . . 11,820 1,839 13,659
Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . 199,452 41,933 241,385
Total proved reserves (MMcfe) . . . . . . . . . . . . . 270,372 52,967 323,339
Present value of estimated future pre-tax net
cash flows (in thousands) . . . . . . . . . . . . . . . $748,657 $111,159 $859,817
</TABLE>
Ryder Scott Company, Petroleum Engineers ("Ryder Scott"), has prepared
estimates of the Company's proved reserves and future net cash flows therefrom
as of December 31, 1992, 1993, 1994, 1995 and 1996. Ryder Scott's estimates of
equivalent proved reserves were 100.3%, 97.8%, 106.0%, 100.5% and 96.3%,
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 105.7%, 102.4%,
107.9%, 102.4% and 93.7% 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
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 revision 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
-8-
<PAGE> 11
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).
FINDING COSTS
The following table sets forth certain information regarding the costs
associated with finding, acquiring and developing the Company's 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> <C>
1992 . . . . . . . . . . . . . . . . . . . . . . . $ 34,777 39,257 $0.89
1993 . . . . . . . . . . . . . . . . . . . . . . . 43,126 72,164(2) 0.60(2)
1994 . . . . . . . . . . . . . . . . . . . . . . . 116,476 97,513 1.19
1995 . . . . . . . . . . . . . . . . . . . . . . . 103,511 102,580 1.01
1996 . . . . . . . . . . . . . . . . . . . . . . . 162,315 119,050 1.36
-------- -------
Five-year period ended December 31, 1996 . . . $460,205 430,564 $1.07
======== =======
</TABLE>
- ---------------
(1) Capitalized costs represent all capitalized expenditures of the Company as
shown in the following table under the
caption "--Development, Exploration and Acquisition Capital Expenditures,"
excluding interest capitalized.
(2) Reserves added during 1993 include 10,088 MMcfe of reserves attributable
to the Company's reversionary interests in certain properties that had
not previously been included in the reserve estimates. Cost to find and
develop per Mcfe for 1993 is $0.69 without taking into account the addition
of reserves attributable to such reversionary interests. See "--Oil and
Gas Reserves."
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,
-----------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Property acquisition:
Unproved properties . . . . . . . . . . . . . . $ 5,670 $ 10,154 $ 2,020 $ 1,422 $ 749
Proved properties . . . . . . . . . . . . . . . 28,480 29,393 32,810 17,694 13,844
Exploration . . . . . . . . . . . . . . . . . . . 48,525 32,518 17,710 9,197 5,315
Development . . . . . . . . . . . . . . . . . . . 79,640 31,446 63,936 14,813 14,869
Interest capitalized . . . . . . . . . . . . . . 1,508 674 217 119 119
-------- -------- -------- ------- --------
Total capitalized costs . . . . . . . . . . . . $163,823 $104,185 $116,693 $43,245 $ 34,896
======== ======== ======== ======= ========
</TABLE>
-9-
<PAGE> 12
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company
for each year of the three-year period ended December 31, 1996.
<TABLE>
<CAPTION>
1996 1995 1994
-------------- -------------- ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Productive . . . . . . . . . . . . . . . . . 8 4.5 10 4.7 6 3.6
Nonproductive . . . . . . . . . . . . . . . . 7 3.4 6 3.9 3 1.7
-- --- -- --- -- ---
Total . . . . . . . . . . . . . . . . . 15 7.9 16 8.6 9 5.3
== === == === == ===
Development wells:
Productive . . . . . . . . . . . . . . . . . 24 10.1 12 4.0 16 8.6
Nonproductive . . . . . . . . . . . . . . . . 1 0.3 3 2.0 3 1.9
-- ---- -- --- -- ----
Total . . . . . . . . . . . . . . . . . 25 10.4 15 6.0 19 10.5
== ==== == === == ====
</TABLE>
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and gas
wells in which the Company owned an interest as of December 31, 1996.
<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 . . . . . . . . . . . . . 7 56 31.6 - - 56 31.6
Gas . . . . . . . . . . . . . 47 76 38.5 24 3.8 100 42.3
State
Oil . . . . . . . . . . . . . - 1 0.7 - - 1 0.7
Gas . . . . . . . . . . . . . 1 1 0.7 - - 1 0.7
Onshore Louisiana
Gas . . . . . . . . . . . . . - 2 1.5 - - 2 1.5
Offshore Texas
Federal
Oil . . . . . . . . . . . . . 1 7 3.3 - - 7 3.3
Gas . . . . . . . . . . . . . 3 8 3.9 - - 8 3.9
-- --- ---- -- --- --- ----
Total . . . . . . . . . . . 59 151 80.2 24 3.8 175 84.0
== === ==== == === === ====
</TABLE>
ACREAGE DATA
The following table sets forth certain information regarding the
Company's developed and undeveloped lease acreage as of December 31, 1996.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
----------------- -----------------
GROSS NET GROSS NET
------ --- ----- ---
<S> <C> <C> <C> <C>
Offshore Louisiana:
Federal waters . . . . . . . . . . . . . . . . . . . . . 275,280 123,837 49,102 33,687
State waters . . . . . . . . . . . . . . . . . . . . . . 3,153 2,177 4,613 4,339
Onshore Louisiana . . . . . . . . . . . . . . . . . . . . . 3,438 2,212 6,767 3,231
Offshore Texas:
Federal waters . . . . . . . . . . . . . . . . . . . . . 31,680 14,784 5,760 2,448
State waters . . . . . . . . . . . . . . . . . . . . . . - - - -
-------- ------- ------ ------
Total . . . . . . . . . . . . . . . . . . . . . . . . 313,551 143,010 66,242 43,705
======= ======= ====== ======
</TABLE>
-10-
<PAGE> 13
Leases covering approximately 5,000 (875 net to the Company), 2,195
(1,921 net to the Company), 18,178 (11,741 net to the Company), 32,318 (27,287
net to the Company) and 18,098 (12,338 net to the Company) undeveloped acres
are scheduled to expire in 1997, 1998, 1999, 2000 and 2001, 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 which 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 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.
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 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, 1997) 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 . . . . . . . . . . . . 62 Chairman of the Board, President and Chief Executive Officer
Robert W. Waldrup . . . . . . . . . . 52 Vice President-Operations and Director
Terry W. Rathert . . . . . . . . . . 44 Vice President, Chief Financial Officer and Secretary
David F. Schaible . . . . . . . . . . 37 Vice President -Acquisitions & Development
William D. Schneider . . . . . . . . 45 Manager-Exploration
Ronald P. Lege . . . . . . . . . . . 52 Controller and Assistant Secretary
C. William Austin . . . . . . . . . . 44 Legal Counsel and Assistant Secretary
James P. Ulm, II . . . . . . . . . . 34 Treasurer
</TABLE>
Each of the executive officers has held the position set forth
opposite his name for the past five years except as follows:
Terry W. Rathert has served as Vice President, Chief Financial Officer
and Secretary of the Company since 1992. From 1989 to 1992, he coordinated the
Company's planning and marketing activities.
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. Mr. Schaible was employed
by the Company as Coordinator-Acquisitions and Marketing from 1991 to 1992 and
as a petroleum engineer from 1989 to 1991.
William D. Schneider has served as Manager-Exploration of the Company
since 1992. From 1989 to 1992, Mr. Schneider was employed by the Company as a
geologist.
-11-
<PAGE> 14
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, an independent oil
and gas company headquartered in Houston, Texas.
-12-
<PAGE> 15
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 high and low sales price per share for the Common Stock.
HIGH LOW
---- ---
[S] [C] [C]
1995
First Quarter . . . . . . . . . . . . . . . . . . 11 7/16 9
Second Quarter . . . . . . . . . . . . . . . . . 14 1/4 10 3/4
Third Quarter . . . . . . . . . . . . . . . . . . 16 1/16 12 3/8
Fourth Quarter . . . . . . . . . . . . . . . . . 15 1/4 13 5/16
1996
First Quarter . . . . . . . . . . . . . . . . . . 15 1/4 12 1/2
Second Quarter . . . . . . . . . . . . . . . . . 20 15 1/8
Third Quarter . . . . . . . . . . . . . . . . . . 22 3/4 18 1/16
Fourth Quarter . . . . . . . . . . . . . . . . . 26 1/2 22 5/16
1997
First Quarter (through February 28, 1997) . . . . 28 19
On December 1, 1996 the Company's Board of Directors declared a
two-for-one split of its outstanding Common Stock to stockholders of record on
December 16, 1996. All share amounts above have been restated to retroactively
reflect the stock split.
On February 28, 1997 the last reported sale price on the New York
Stock Exchange Composite Tape was $19.875 per share.
As of February 28, 1997 there were approximately 301 holders of record
of the Common Stock of the Company.
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 earnings, if any, 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. 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 11 of the Newfield
Exploration Company Annual Report to Stockholders for the year ended December
31, 1996 (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 12 through 17 of the
Annual Report, which information is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For information concerning this item, see pages 18 through 40 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.
-13-
<PAGE> 16
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 1, 1997, 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 18 through 40 of the Annual Report, and are incorporated herein by
reference:
Management Report on Financial Statements
Report of Independent Accountants
Balance Sheet as of the fiscal years ended December 31, 1996 and 1995
Statement of Income for the three years in the period ended December
31, 1996
Statement of Cash Flows for the three years in the period ended
December 31, 1996
Statement of Stockholders' Equity for the three years in the period
ended December 31, 1996
Notes to the Financial Statements
2. EXHIBITS
3.1 - Second Restated Certificate of Incorporation of Registrant
(incorporated by reference to Exhibit 3.1 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-69540)).
3.2 - Restated Bylaws of Registrant.
+10.1 - Newfield Exploration Company 1989 Stock Option Plan
(incorporated by reference to Exhibit 10.1 to the
Registrant'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
Registrant'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
Registrant'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
Registrant'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
Registrant's Registration Statement on Form S-1
(Registration No. 33-69540)).
-14-
<PAGE> 17
+10.6 - Restricted Stock Plan and Agreement (incorporated by
reference to Exhibit 10.6 to the Registrant'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 Registrant's Registration Statement on
Form S-1 (Registration No. 33-69540)).
10.8 - Credit Agreement among Newfield Exploration Company and the
Chase Manhattan Bank, N.A., as Agent, and the Banks
signatory thereto (without exhibits) dated as May 20, 1996
(incorporated by reference to Exhibit 10.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1996).
+10.9 - Newfield Exploration Company 1995 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1 to the
Registrant's Registration Statement of Form S-8
(Registration No. 33-92182)).
+10.10 - Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (incorporated by reference to Exhibit
4.2 to the Registrant's Registration Statement on Form S-8
(Registration No. 33-92182)).
*11.1 - Computation of Earnings per Share.
*13.1 - Newfield Exploration Company Annual Report to Stockholders
for the year ended December 31, 1996.
21.1 - The Registrant has no subsidiaries.
*23.1 - Consent of Coopers & Lybrand L.L.P.
*23.2 - Consent of Ryder Scott Company.
*27 - 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
On December 13, 1996, the Company filed a Current Report on Form 8-K,
dated December 3, 1996, reporting the declaration of a two-for-one stock split
of its outstanding Common Stock on December 1, 1996.
-15-
<PAGE> 18
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 5th day of March, 1997.
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.
Signature Title Date
--------- ----- ----
/s/ Joe B. Foster Chairman of the Board and March 5, 1997
- -------------------------- Chief Executive Officer
Joe B. Foster (Principal Executive Officer)
/s/ Robert W. Waldrup Vice President - Operations March 5, 1997
- -------------------------- and Director
Robert W. Waldrup
/s/ Terry W. Rathert Vice President, Chief Financial March 5, 1997
- -------------------------- Officer and Secretary
Terry W. Rathert (Principal Financial Officer)
/s/ Ronald P. Lege Controller and Assistant Secretary March 5, 1997
- -------------------------- (Principal Accounting Officer)
Ronald P. Lege
/s/ Charles W. Duncan, Jr Director March 5, 1997
- --------------------------
Charles W. Duncan, Jr.
/s/ Jeffrey A. Harris Director March 5, 1997
- --------------------------
Jeffrey A. Harris
/s/ Howard H. Newman Director March 5, 1997
- --------------------------
Howard H. Newman
/s/ Thomas G. Ricks Director March 5, 1997
- --------------------------
Thomas G. Ricks
/s/ C. E. Shultz Director March 5, 1997
- --------------------------
C.E. Shultz
/s/ Dale E. Zand Director March 5, 1997
- --------------------------
Dale E. Zand
-16-
<PAGE> 19
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
3.1 - Second Restated Certificate of Incorporation of Registrant
(incorporated by reference to Exhibit 3.1 to the Registrant's
Registration Statement on Form S-1 (Registration No. 33-69540)).
3.2 - Restated Bylaws of Registrant.
+10.1 - Newfield Exploration Company 1989 Stock Option Plan incorporated
by reference to Exhibit 10.1 to the Registrant'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 Registrant'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 Registrant'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 Registrant'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 Registrant'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 Registrant'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 Registrant's Registration Statement on Form S-1
(Registration No. 33-69540)).
10.8 - Credit Agreement among Newfield Exploration Company and the
Chase Manhattan Bank, N.A., as Agent, and the Banks signatory
thereto (without exhibits) dated as May 20, 1996 (incorporated
by reference to Exhibit 10.1 to the Registrant's Quarterly
Report on Form 10-Q for the quarterly period ended June 30,
1996).
+10.9 - Newfield Exploration Company 1995 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement of Form S-8 (Registration No. 33-92182)).
+10.10 - Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (incorporated by reference to Exhibit 4.2
to the Registrant's Registration Statement on Form S-8
(Registration No. 33-92182)).
*11.1 - Computation of Earnings per Share.
*13.1 - Newfield Exploration Company Annual Report to Stockholders
for the year ended December 31, 1996.
21.1 - The Registrant has no subsidiaries.
*23.1 - Consent of Coopers & Lybrand L.L.P.
*23.2 - Consent of Ryder Scott Company.
*27 - Financial Data Schedule (included only in the electronic
filing of this document)
- ------------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
<PAGE> 1
Exhibit 11.1
NEWFIELD EXPLORATION COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
(In thousands of dollars, except share and per share amounts)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1996 1995 1994
----------- ----------- ----------
<S> <C> <C> <C>
Net income for earnings per share . . . . . . . . . . . . . . . . $ 38,494 $ 16,264 $ 14,440
=========== =========== ==========
Earnings per common share . . . . . . . . . . . . . . . . . . . . $ 1.03 $ 0.45 $ 0.40
=========== =========== ==========
Calculation of weighted average
shares outstanding:
Common stock, weighted average . . . . . . . . . . . . . . . . 34,873,163 33,940,272 33,197,954
Common stock equivalents . . . . . . . . . . . . . . . . . . . 2,329,382 2,252,830 2,712,394
---------- ---------- ----------
Total common stock and equivalents outstanding
for earnings per common share . . . . . . . . . . . . . . . 37,202,545 36,193,102 35,910,348
========== ========== ==========
</TABLE>
<PAGE> 1
EXHIBIT 13.1
[NEWFIELD LOGO]
[NEWFIELD 1996 ANNUAL REPORT]
[PICTURE OF VERMILION 398 "A" PLATFORM,
OFFSHORE LOUISIANA, IN THE GULF OF MEXICO]
<PAGE> 2
CONTENTS
Financial and Operating Highlights 1
Stockholders' Letter 2
Operations 4
Five-Year Financial and Reserve Data 11
Management's Discussion and Analysis 12
Report of Independent Accountants 19
Financial Statements 20
Notes to Financial Statements 24
Corporate Information inside back cover
On the Cover: The Vermilion 398 "A" Platform was set in 377 feet of water,
offshore Louisiana, in the Gulf of Mexico, approximately 190 miles southwest of
New Orleans. When the development drilling and completion program commenced in
1996 is finished, net daily production is expected to exceed 18,000 Mcfe. The
cover photograph was taken by Jack Burman, a Newfield production engineer.
All production, reserve and dollar figures in the text of this report are net
to Newfield Exploration Company unless otherwise stated.
PROFILE
Newfield Exploration Company (NYSE-NFX) explores, develops and acquires oil and
natural gas properties in the Gulf of Mexico. At December 31, 1996, 75% of the
Company's proved reserves were natural gas and 84% were proved developed.
STRATEGY
Newfield plans to continue to expand its reserve base and increase cash flow
through the exploration and development of existing properties and the
acquisition of properties with drilling upside. The Company emphasizes:
o Reserve growth through exploratory drilling
o Balanced capital program between exploration and acquisition of proved
properties
o Geographic focus in the Gulf of Mexico
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 highly competent
employees
From inception through December 31, 1996, Newfield has added a total of 515.8
billion cubic feet of natural gas equivalent (Bcfe) of proved reserves.
Exploratory and development activities have resulted in the addition of 325.1
Bcfe of net proved reserves. The Company's acquisition of interests in over 90
leases in fields offshore Louisiana and Texas, have contributed 190.7 Bcfe of
net reserves. Newfield's proved reserve replacement as a percent of production
was 209% in 1996.
[PICTURE OF OFFSHORE PLATFORM IN THE GULF OF MEXICO.]
Simultaneous drilling and producing operations at the Ewing Bank 947 "A"
Platform allowed for production during the drilling campaign which began
late in 1995 and was completed in late 1996. Ewing Bank 947 was a key
component of Newfield's balanced capital program which contributed to
record operating results in 1996.
<PAGE> 3
FINANCIAL
AND OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
============================================================================================
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
FINANCIAL SUMMARY
<S> <C> <C> <C>
Revenues ........................................... $ 149,256 $ 94,598 $ 69,728
Income before income taxes ......................... $ 59,286 $ 25,006 $ 22,548
Income tax provision ............................... $ 20,792 $ 8,742 $ 8,108
Net income ......................................... $ 38,494 $ 16,264 $ 14,440
Earnings per common share .......................... $ 1.03 $ 0.45 $ 0.40
Weighted average number of common shares ........... 37,203 36,193 35,910
CASH FLOW
Cash flow from operations before changes
in assets and liabilities .................. $ 125,226 $ 75,613 $ 57,535
BALANCE SHEET
Working capital ................................. $ 11,436 $ 11,235 $ 10,987
Long-term debt and capital lease obligations .... $ 60,000 $ 25,152 $ 555
Stockholders' equity ............................ $ 239,902 $ 193,571 $ 169,491
OPERATING SUMMARY
ESTIMATED OIL AND GAS RESERVES
Net proved reserves:
Oil (MBbls) ................................ 13,659 9,633 8,610
Natural gas (MMcf) ......................... 241,385 203,580 153,967
Gas equivalents (MMcfe) .................... 323,339 261,378 205,627
OIL AND GAS OPERATIONS
Production:
Oil (MBbls) ................................ 2,558 2,071 1,394
Natural gas (MMcf) ......................... 41,323 33,719 24,267
Gas equivalents (MMcfe) .................... 56,670 46,145 32,631
Average realized prices:
Oil (per Bbl) .............................. $ 20.89 $ 17.23 $ 15.73
Natural gas (per Mcf) ...................... $ 2.32 $ 1.75 $ 1.97
</TABLE>
[TWO GRAPHS, ONE SHOWING OIL & GAS RESERVES AND PRODUCTION GROWTH FROM 1992 TO
1996, THE OTHER SHOWING REVENUE, CASH FLOW AND NET INCOME GROWTH FROM 1992 TO
1996.]
1
<PAGE> 4
DEAR FELLOW
STOCKHOLDERS
Our job at Newfield is to find, acquire, and develop oil and gas reserves to
add economic value on a per share basis. After taking into account our
two-for-one stock split in December 1996, here is our scorecard for 1996:
<TABLE>
<CAPTION>
PERCENT
FOR THE YEAR 1996 1995 CHANGE
- ------------ ---- ---- ------
<S> <C> <C> <C>
Net income per share $ 1.03 $ 0.45 +129%
Operating cash flow $ 3.37 $ 2.09 + 61%
per share
Net production per share 1.52 1.27 + 19%
(Mcfe)
AT YEAR END
- -----------
Market price per share $ 26.00 $ 13.50 + 93%
Book value per share $ 6.45 $ 5.35 + 21%
SEC 10 value less long- $ 21.50 $ 9.39 +129%
term debt per share
Reserves per share (Mcfe) 8.69 7.22 + 20%
</TABLE>
These are excellent results, and we are quite proud of them. But you know,
and I know, there was a rising tide which lifted all boats in 1996. The market
was strong, especially for energy stocks. Further, oil and gas prices were
quite robust. Nevertheless, Newfield outperformed its peer group and the market
indices against which we compare ourselves during the year. A graph in the
photograph below illustrates this.
Our retained earnings reached $95 million by year-end 1996. Newfield was
started at the beginning of 1989 with $9 million of paid-in capital. To have
created $95 million of retained earnings and $860 million of SEC 10 value (i.e.,
net present value of remaining oil and gas reserves at year-end 1996 prices,
discounted at 10%), from that start in eight years is a source of great
satisfaction for those of us who have been involved!
During 1996, Newfield's annual production totaled 56.7 Bcfe - up 23% from
1995.
Operating cash flow was $125.2 million, up from $75.6 million in 1995 - a
66% increase.
Growing production volumes helped us maintain our unit lease operating
costs for the year at 30(cents)/Mcfe, compared to 31(cents)/Mcfe in 1995.
Administrative & General costs were up from l4(cents)/Mcfe in 1995 to
17(cents)/Mcfe in 1996. Virtually all of the increase was due to an increase in
performance-based pay. If prices or margins were to go down, performance-based
pay would decrease, and A & G per unit would decrease.
On a unit of production basis, the bottom line is this: During 1996, we had
$2.21/Mcfe of cash flow available for reinvestment out of unit revenue of
$2.63/Mcfe. In 1995, our unit cash flow available for reinvestment was
$1.64/Mcfe out of $2.05/Mcfe of revenue. Of the 58(cents)/Mcfe increase in
revenue, we were able to keep 57(cents) of it for reinvestment!!
Capital investment for 1996 totaled $164 million, up from $104 million in
1995.
Reserve additions during the year were 118.6 Bcfe, compared to the 56.7
Bcfe of production - a 209% reserve replacement figure.
Our capital investment per unit of reserves added is reflected in our DD&A
(Depreciation, Depletion and Amortization) rate, which was $1.13/Mcfe during
1996. This includes not only capital costs to find and develop existing
reserves, but future costs associated with developing proved undeveloped
reserves and abandoning wells and platforms when the reserves are depleted.
Our balance sheet remains strong. We ended the year with long-term debt of
$60 million or 20% debt to total capitalization.
Let's talk now about 1997:
First, our 1997 production target is about 20% greater than our 1996
production.
We are now at full rate at Ewing Bank 947, a site of active 1996
development drilling. Our gross production rate exceeds 40 MMcf/d of gas and
2,000 b/d of oil and condensate. Newfield's net revenue interest is 47%.
South Timbalier 148 W/2 is producing at gross daily rates of 42 MMcf of gas
and 2,500 barrels of oil and condensate. Our net revenue interest is about 30%.
West Delta 152 "A" Platform has a productive capacity of 27 MMcf/d of gas
and 2,900 b/d of oil and condensate. Development drilling continues on this
[CHART OF NEWFIELD STOCK PRICE PERFORMANCE VERSUS S&P 500 INDEX DURING 1996.]
2
<PAGE> 5
platform, where Newfield's net revenue interest ranges from 25 to 35%.
We commenced production from Vermilion 398. This project required more than
$20 million of capital investment during 1996, yet will not result in reserve
additions until 1997. In addition to the one well completed on this platform,
there are two previously drilled wells to be re-entered and one additional well
will be drilled.
In the fourth quarter of 1997, we plan to initiate production from Ship
Shoal 354, West Cameron 560/561, and from a subsea completion at Mississippi
Canyon 357.
We expect also to drill at least three wells at Ship Shoal 69 and two or
three wells in the East Cameron 45/46/64 areas.
All of this gives us confidence that we can meet our 1997 production target
and go into 1998 with momentum for continued production growth.
We have firm drilling locations for fifteen exploratory tests during 1997.
As this is being written, we have three wildcats being drilled: at Bayou Sale
(onshore), Ship Shoal 170, and South Timbalier 111. During 1996, eight of the
fifteen exploratory tests drilled by Newfield were productive.
Our current capital budget for 1997 is $148 million. Remember that our
budgets represent the cost of work we know we will do as opposed to being an
estimate of how much we would like to invest. At this time a year ago, our
budgeted expenditures were $85 million, and we finished 1996 with $164 million
in capital investment.
So we see a busy 1997 ahead of us.
There are some concerns about rig availability. We deferred some activity
planned for 1996 into 1997 and there has been some slippage in our 1997
program. The problem is not so much getting rigs as it is getting them when we
want them. We have about equal incidences of rigs coming available on short
notice as of rigs being delayed. We have learned to be very flexible--ready to
accommodate our plans to rig availability rather than attempting to dictate the
rig schedule. I think our ability to move quickly will pay off for us
throughout the year.
Just a word about "hedging," or forward gas sales:
During 1996, we sold a substantial amount of our gas forward to assure
returns and cash flow. The result was that our average gas price for the year
was $2.32/Mcf. With no hedges, we would have realized $2.70/Mcf.
For 1997, we have hedged enough of our first quarter gas production such
that we would not expect to realize less than $2.45/Mcf, nor more than
$2.75/Mcf in that quarter. Currently, we also have 2.4 Bcf of second quarter
production sold forward at $2.08/Mcf and none of our 1997 oil and condensate
production is hedged.
Finally, you probably noticed the steep drop in Newfield's stock price in
early February from $26 to $20 per share. I own enough stock that it got my
attention!
There was nothing related to production volumes or reserves or drilling
activity to prompt the price change. My assumption is that many in the market
concurrently concluded that oil and gas prices were likely to be less robust
than anticipated, and--for a time--there were simply more profit-takers than
profit-seekers in the market for Newfield stock. This happens, even in so
called efficient markets.
Nevertheless, I have confidence that if we keep adding reserves, growing
production, controlling costs, and generating attractive investment
opportunities, the market will treat us fairly.
The very successful year recounted in this Annual Report is the result of
the creative thought and hard work of a group of talented employees, supported
by a very cooperative oil field service industry. I am grateful to each person
who helped us "add economic value"--and had fun doing it--during 1996.
I am also grateful for the support of all stockholders--profit-takers,
profit-seekers, and long-term investors. It takes them all to make a market.
/s/ JOE
Joe B. Foster
February 17, 1997
[PICTURE OF NEWFIELD MANAGEMENT GROUP REVIEWING DRILLING RESULTS.]
The primary focus of Newfield's management group is to add economic value
on a per share basis. Here David F. Schaible, William D. Schneider, Robert
W. Waldrup, Terry W. Rathert and Joe B. Foster review drilling results
from the Mississippi Canyon 357 #2 discovery.
3
<PAGE> 6
1996 RESULTS - RECORD OPERATING PERFORMANCE
Newfield accomplished record increases in net income and cash flow in 1996, due
primarily to a successful capital investment program and improved operating
results. Measures of Newfield's 1996 performance can be highlighted as follows:
OIL AND GAS:
PROVED RESERVES UP 24%
PRODUCTION UP 23%
PRICE REALIZATIONS UP 28%
EARNINGS UP 137%
OPERATING CASH FLOW UP 66%
RESERVE REPLACEMENT - Newfield replaced 209% of its 1996 production with 118.6
Bcfe of new proved reserves; the fourth consecutive year of reserve replacement
in excess of 200%. Proved reserves at the end of 1996 were 323.3 billion cubic
feet of natural gas equivalent (Bcfe), up 24% from the prior year. During the
year, Newfield was successful in 80% of its wells, including eight exploratory
discoveries and 24 commercially productive development wells. The Company also
completed several purchases of proved reserves with additional drilling
potential. Capital expenditures for the year totaled $164 million, including
$136 million for exploration and development and $28 million for the
acquisition of proved properties. The results for 1996 reflect the continued
success in this phase of Newfield's strategy to balance exploratory drilling
and property acquisitions.
INCREASED PRODUCTION - Oil and gas production increased 23% during 1996 to a
level of 56.7 Bcfe, up from 46.1 Bcfe in the previous year. On an equivalent
basis, daily production grew from 126.4 million cubic feet of natural gas
equivalent (MMcfe) to 154.8 MMcfe, primarily as a result of a full year's
production at Vermilion Block 355 and in the Vermilion 306 Area. Additionally,
production from completed drilling programs at Ewing Bank 947, South Timbalier
148 W/2 and Vermilion 308 and the acquisition of proved producing properties in
the Ship Shoal 69 Field contributed in the second half of 1996.
LOW OPERATING COSTS - Newfield maintained its low operating cost structure with
all-in costs (including lease operating, depreciation, depletion and
amortization and G&A) of $1.56 per Mcfe. Historically, Newfield has been one of
the lowest cost producers in the Gulf of Mexico. In a research report prepared
by Donaldson, Lufkin & Jenrette in September 1996, Newfield ranked first in
terms of the lowest five year historical operating costs, G&A expense, net
interest expense and cash operating costs, and ranked second highest in
operating cash flow, all measured on a per unit of production basis. The report
compared the results of 16 publicly traded oil and gas companies, and is
summarized on page 6.
HIGHER COMMODITY PRICES - Average oil and gas price realizations increased
during 1996 to $20.89 per barrel and $2.32 per Mcf, up from the earlier year's
levels of $17.23 per barrel and $1.75 per Mcf. Coupled with higher production
levels, oil and gas revenues rose to $149 million, or $2.63 per Mcfe.
[PICTURE OF DRILLING AND PRODUCTION ENGINEERS DISCUSSING PLANS FOR SUBSEA
COMPLETION.]
Advanced technology plays an important role in all of Newfield's
operations. A team of drilling and production engineers discuss plans for
a subsea completion and tieback for the Mississippi Canyon 357 #2 wildcat
discovery.
4
<PAGE> 7
RECORD EARNINGS AND CASH FLOW - The impact of increased production and higher
price realizations combined with a low cost operating structure resulted in
record financial results during 1996. Net income was $38.5 million, or $1.03
per share, up 137% from 1995 when net income was $16.3 million, or $0.45 per
share. Since Newfield's formation in 1989, the Company has generated retained
earnings of $95 million. Operating cash flow before changes in working capital
increased 66% from $75.6 million, or $2.09 per share in the previous year, to
$125.2 million, or $3.37 per share in 1996. On a per unit basis, oil and gas
revenues per Mcfe rose $0.58, and, of that amount, $0.57 per Mcfe was cash flow
available for reinvestment in Newfield's capital expenditure programs.
CAPITAL PROGRAM
Newfield's strategy for growth is focused in the Gulf of Mexico and predicated
upon the extensive application of 3-D seismic and other advanced technologies
to a balanced program of exploratory drilling and proved property acquisitions.
Three examples of the successful employment of this strategy are Ewing Bank
947, West Delta 152 and South Timbalier 148 W/2, where Newfield operated active
drilling programs throughout most of 1996.
EWING BANK 947 - In November 1995, a platform rig installed at Ewing Bank 947
began a drilling program that included six wells. The well locations were
identified using a 3-D seismic survey and included proved undeveloped, probable
and exploratory targets. Five of the six wells were successful. When the
platform rig was demobilized in late 1996, gross daily production rates
increased significantly to levels in excess of 50 MMcfe, as shown in the chart
on the right. Newfield acquired an initial 50% working interest in 1994, and
subsequently increased its interest to 62% with the acquisition of other
interests in the block.
WEST DELTA 152 - In January 1995, Newfield acquired its initial interest in the
West Delta 152 Field, which included a 23% working interest in the proved
reserves and a 34% interest in the exploratory potential. Subsequently,
additional interests were acquired, farm-in acreage was obtained and the
adjacent Mississippi Canyon Block 358 was awarded to the Company in the May
1995 Federal OCS Lease Sale. Newfield initiated a five well drilling program
with a platform rig at West Delta 152 during the fourth quarter 1995. The wells
were designed to test proved undeveloped, probable and exploratory objectives
generated using a 3-D seismic survey. All five of the wells were commercially
productive, including one exploratory and four development wells. The
exploratory discovery, West Delta 152 A-14 ST#1, encountered 112 feet of gas
pay, and was followed by a successful development well. The wells have been
completed and placed on production at combined gross daily rates in excess of
45 MMcfe. Due to the success of the initial drilling and based upon additional
seismic analysis, a second five well drilling program has been initiated and is
expected to be completed in the second quarter 1997.
SOUTH TIMBALIER 148 W/2 - In late 1996, Newfield resumed its active program at
South Timbalier 148 W/2. Platforms and facilities were installed at the "D" and
"E" locations which permitted six wells, including four exploratory discoveries
and a development well drilled during 1995, and a development well drilled in
1996, to be placed on production. The South Timbalier 148 D-4 well will be
drilled and completed during 1997. To date, gross daily production rates have
increased to over 55 MMcfe from four MMcfe.
EXPLORATION
The exploration component of Newfield's capital program included the drilling
of 15 wildcats, eight of which were successful, for a 53% success ratio.
In addition to the exploratory discovery drilled at West Delta 152,
Newfield drilled discoveries at Ship Shoal 354, Mississippi Canyon 357, West
Cameron 560/561 and in the Vermilion 306 Area.
SHIP SHOAL 354 - Newfield drilled the Ship Shoal 354 #1 wildcat in May 1996 to
a total measured depth of 16,138 feet, encountering 141 feet of gas and
condensate pay in three sands. Subsequently, the Ship
[EWING BANK 947 "A" PLATFORM WITH GRAPH SHOWING PRODUCTION INCREASES DURING
1996]
During 1996, Newfield participated in 40 wells, including 8 wildcat
discoveries and 24 commercially productive development wells, for an
overall success ratio of 80%. Five of the six wells drilled at Ewing Bank
947 were successful and contribute to current gross production rates over
50 MMcfe per day.
5
<PAGE> 8
Shoal 354 #2 delineation well was drilled, encountering 160 feet of gas and
condensate pay in three sands. The water depth at this location is 463 feet.
Construction of a four pile platform and facilities has begun with installation
scheduled for the third quarter 1997. Initial production is expected January 1,
1998. Ship Shoal Block 354 was acquired in the May 1995 Federal OCS Lease Sale
for $505,000 and Newfield's working interest is 48%.
MISSISSIPPI CANYON 357 - In connection with the evaluation of the West Delta
152 Field, Newfield recognized a prospect on the northwest flank of its salt
dome. The Mississippi Canyon 357 #2 was the first test of the northwest flank
of the West Delta 152 salt dome since the acquisition and interpretation of a
modern 3-D seismic survey. The well was drilled in 445 feet of water with a
semi-submersible drilling rig to a depth of 19,644 feet in November 1996, and
encountered 100 feet of net pay. Newfield has started the design for a subsea
completion to be tied back to the West Delta 152 platform. The estimated date
of initial production is the fourth quarter 1997. The Company earned a 32%
working interest in this acreage through a farm-in.
WEST CAMERON 560/561 - Newfield also farmed into West Cameron Blocks 560 and
561 and drilled two successful exploratory discoveries. The West Cameron 561 #3
well drilled to a total depth of 9,640 feet and found 135 feet of net pay.
Subsequently, the Company drilled the West Cameron 560 #3 exploratory well and
West Cameron 560 #4 development well. A used platform has been acquired and
will be refurbished and installed in the third quarter 1997 with production
expected to commence shortly thereafter.
Newfield also participated in a successful three well exploratory drilling
program in the Vermilion 306 Area. All three discoveries were placed on
production in the first quarter 1996 with current gross daily rates of 10
MMcfe. Enron Oil & Gas Company is the operator and Newfield's working interest
is 38%.
DEVELOPMENT
Newfield successfully drilled 24 of 25 development wells in 1996. In addition
to the development activities discussed previously, Newfield conducted drilling
programs at Vermilion 398, East Cameron 64, and Vermilion 308.
VERMILION 398 - Newfield began its development program at Vermilion 398 during
1996 when a four pile platform was installed in 377 feet of water and a
platform rig was erected. Planned operations include the completion of two and
sidetrack of one of the wells which were drilled by the previous operator and
the drilling of one additional well. Preliminary results from the drilling of
the new well confirm the Company's estimate of project reserves made at the
time of the acquisition. Although the well found more gas pay and less oil pay
than expected, peak field production rates on an oil equivalent basis are still
expected to reach 3,000 barrels per day, net to the Company, in the third
quarter 1997. Newfield owns an 85% working interest in this field.
EAST CAMERON 64 - A multi-well drilling program was
[LOW COST OPERATING STRUCTURE CHART SHOWING NEWFIELD AS COMPARED TO
INDUSTRY AVERAGES FOR LAST 5 YEARS FOR LEASE OPERATING AND G&A EXPENSE
AND CASH FLOW, ON A PER UNIT OF PRODUCTION BASIS.]
On a unit of production basis, Newfield has maintained one of the lowest
cost structures in the industry. A low cost structure contributes to
earnings and high levels of cash flow available for reinvestment. Source:
Donaldson, Lufkin & Jenrette - September 1996 report comparing five year
results for 16 publicly traded companies.
6
<PAGE> 9
started in mid-1996 in the East Cameron 64 Field to test proved undeveloped,
probable and exploratory targets. To date, three development wells have been
drilled, one of which had a successful deeper exploratory target. Two
additional wells are planned to be drilled in the second quarter 1997. As a
result of the development drilling and extensive workover activities, daily
gross production has more than doubled compared to 1995. Newfield is operator
with an l8% working interest in the East Cameron 64 Field.
VERMILION 308 - During 1996, Newfield installed a four pile platform and
deepened an existing well to establish production related to a 1995 exploratory
discovery, the Vermilion 308 #3. Initial production began in the fourth quarter
1996, where Newfield earned an 85% working interest via farm-in.
ACQUISITIONS
An important source of new drilling opportunities is the acquisition of proved
properties with exploratory potential or undeveloped acreage. Newfield pursues
acquisitions through offerings in data rooms, making unsolicited offers and
through negotiated transactions. In 1996, Newfield acquired interests in 12
offshore blocks in 5 fields and purchased an onshore South Louisiana field.
Each of the properties has identified drilling prospects for 1997.
SHIP SHOAL 69 - Newfield purchased a 75% working interest in the Ship Shoal 69
Field in September 1996. At least six locations were identified at the time of
acquisition to test proved undeveloped and probable reserve objectives. A two
well drilling program began in the first quarter 1997. Upon completion of
testing and further permitting, Newfield plans to drill at least one additional
well in this field during 1997. Newfield is the operator of the Ship Shoal 69
Field.
EAST CAMERON 45/46 - Newfield has acquired a 77% working interest in
East Cameron 45/46 in a series of transactions. The East Cameron 45/46 Field is
adjacent to East Cameron 64, where Newfield is operator and is currently
conducting a development program.
RAYNE FIELD - As part of a strategic decision to apply Newfield's geophysical
and operating capabilities to an area with similar geologic characteristics,
Newfield initiated activities in the Gulf Coast parishes of South Louisiana,
and, in early 1996, acquired a 56% working interest in the Rayne Field.
Cumulative production from the Rayne Field is over one trillion cubic feet of
gas and 20 million barrels of condensate. Newfield is shooting a 3-D seismic
survey to further evaluate deep drilling opportunities for 1997 and beyond.
LEASE SALES
Newfield participated in the Gulf of Mexico Federal OCS Lease Sales in 1996. In
May 1996, Newfield was awarded two tracts at the Central Gulf of Mexico Sale.
At the Western Gulf of Mexico Lease Sale in September, Newfield was the winning
bidder on three blocks. The total amount paid for the blocks awarded to
Newfield during 1996 was $1.4 million. The Company intends to drill on at least
two of these blocks during 1997.
[PICTURE OF OFFSHORE PLATFORM AND NEWFIELD EMPLOYEES AT WORKSTATION.]
The continual generation of new opportunities is crucial to adding value
at Newfield. The use of 3-D seismic and other advanced technologies is
extensive on projects such as Vermilion Block 308 where production
commenced during 1996 from a 1995 discovery.
7
<PAGE> 10
OPERATIONS
The Company has a significant presence as an operator in the Gulf of Mexico.
Based upon a survey completed in January 1997 by the James K. Dodson Company,
Newfield ranked as the eighth most active driller in the Gulf of Mexico in
1996. During the third quarter, which was the most active point in the
Company's 1996 capital program, Newfield was the third most active driller in
the Gulf of Mexico, ranked only behind Shell and Chevron. In terms of gross
operated production on the Outer Continental Shelf of the Gulf of Mexico, the
Company ranked 18th, and, excluding major oils, sixth, based upon publicly
available figures for the third quarter 1996. Newfield currently operates in
excess of 90% of its total equivalent production and owns interests in 59
platforms and 18 pipelines. The Company managed more than $285 million of gross
capital expenditures and had under contract, on average, 4.7 drilling and
completion rigs during 1996.
ADDING VALUE PER SHARE IN 1996
<TABLE>
<CAPTION>
1996 1995
---- ----
<S> <C> <C>
RESERVES AT BEGINNING OF YEAR, 261.4 205.6
BCFE
RESERVE ADDITIONS, BCFE 118.6 101.9
PRODUCTION, BCFE (56.7) (46.1)
RESERVES AT END OF YEAR, BCFE 323.3 261.4
AVG. SHARES OUTSTANDING, MM 37.2 36.2
RESERVES PER SHARE, MCFE 8.69 7.22
PERCENT INCREASE 20%
</TABLE>
In 1996, Newfield continued to add value for its shareholders as measured by
the 20% increase in net reserves per share from the prior year-end. As a result
of the balanced capital investment in exploration, development and acquisition
activities during 1996, the Company increased proved reserves by 24% to 323
Bcfe, replacing 209% of production.
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 in the Company's filing of its Form 10-K.
[MAP OF GULF OF MEXICO REGION SHOWING NEWFIELD'S ASSET BASE.]
Newfield is a significant operator in the Gulf of Mexico with a large
inventory of drillable prospects. The Company's focused strategy includes
a balance between exploration and acquisitions, control of operations for
a low cost structure and the application of 3-D seismic and other advanced
technology.
8
<PAGE> 11
FINANCIAL SECTION CONTENTS
<TABLE>
<S> <C>
Five-Year Financial and Reserve Data . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Management's Discussion and Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Statement of Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Statement of Stockholders' Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Statement of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
</TABLE>
9
<PAGE> 12
[THIS PAGE INTENTIONALLY LEFT BLANK]
10
<PAGE> 13
SELECTED FIVE-YEAR FINANCIAL AND RESERVE DATA
The following table sets forth selected 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
financial statements and notes thereto and supplementary financial information,
which follow.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1996 1995 1994 1993 1992
----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
(in thousands, except per share data)
Oil and gas revenues . . . . . . . . . . $ 149,256 $ 94,598 $ 69,728 $ 60,178 $ 41,427
----------- ----------- ----------- ----------- ----------
Operating expenses:
Lease operating . . . . . . . . . . 16,946 14,227 9,555 7,096 4,151
Depreciation, depletion and amortization 64,026 49,904 34,118 25,116 18,709
General and administrative, net . . . 7,552 5,549 3,802 3,709 1,956
Stock compensation (1) . . . . . . . 1,943 692 1,084 3,235 ---
----------- ----------- ----------- ----------- ----------
Total operating expenses . . . . . $ 90,467 $ 70,372 $ 48,559 $ 39,156 $ 24,816
----------- ----------- ----------- ----------- ----------
Income from operations . . . . . . . . . $ 58,789 $ 24,226 $ 21,169 $ 21,022 $ 16,611
Interest income, net . . . . . . . . . . 497 780 1,379 759 423
----------- ----------- ----------- ----------- ----------
Income before income taxes . . . . . . . $ 59,286 $ 25,006 $ 22,548 $ 21,781 $ 17,034
Income tax provision . . . . . . . . . . 20,792 8,742 8,108 7,753 5,787
----------- ----------- ----------- ----------- ----------
Net income . . . . . . . . . . . . . . $ 38,494 $ 16,264 $ 14,440 $ 14,028 $ 11,247
=========== =========== =========== =========== ==========
Earnings per common share . . . . . . . $ 1.03 $ 0.45 $ 0.40 $ 0.49 $ 0.42
=========== =========== =========== =========== ==========
Weighted average number of shares
outstanding . . . . . . . . . . . . 37,203 36,193 35,910 28,694 26,484
CASH FLOW DATA:
(in thousands of dollars)
Net cash provided by operating
activities before changes in operating
assets and liabilities . . . . . . . $ 125,226 $ 75,613 $ 57,535 $ 48,024 $ 35,543
Net cash provided by operating activities 127,494 67,640 68,121 38,569 30,980
Net cash used in investing activities . (159,537) (99,329) (123,619) (41,382) (34,365)
Net cash provided by financing activities 32,800 33,810 865 57,482 11,499
BALANCE SHEET DATA (AT END OF PERIOD):
(in thousands of dollars)
Working capital . . . . . . . . . . . . $ 11,436 $ 11,235 $ 10,987 $ 70,268 $ 8,196
Oil and gas properties, net . . . . . . 328,615 228,509 173,924 91,136 74,952
Total assets . . . . . . . . . . . . . . 395,938 277,406 215,557 183,683 95,988
Long-term debt and capital lease obligations,
less current maturities . . . . . . 60,000 25,152 555 446 399
Stockholders' equity . . . . . . . . . 239,902 193,571 169,491 152,845 77,934
RESERVE DATA (AT END OF PERIOD)(2):
Proved Reserves:
Oil and condensate (MBbls) . . . . . . 13,659 9,633 8,610 6,414 4,443
Gas (MMcf) . . . . . . . . . . . . . . 241,385 203,580 153,967 102,261 70,375
Total proved reserves (MMcfe) . . . . 323,339 261,378 205,627 140,745 97,033
Present value of estimated future pre-tax
net cash flows (in thousands) . . . . $ 859,817 $ 364,879 $ 230,594 $ 159,155 $ 149,660
</TABLE>
- ------------------------
(1) Stock compensation for 1996, 1995 and 1994 represents noncash stock
compensation charges. Stock compensation for 1993 represents compensation
expense equal to the amount by which the initial public offering price of
$8.75 per share exceeded the exercise price of stock appreciation rights
granted pursuant to the Company's 1989 Stock Option Plan and certain other
noncash stock compensation charges. See Note 6 to the Company's
financial statements.
(2) The reserve data at December 31, 1993 includes 470 MBbls of oil and
condensate, 7,270 MMcf of gas and $10.6 million of present value of
estimated future pre-tax net cash flows attributable to the Company's
reversionary interests in certain properties that were included for the
first time in 1993.
11
<PAGE> 14
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 financial position and results of operations for each year of the
three-year period ended December 31, 1996. The Company's financial statements
and the notes thereto which 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 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 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 "Liquidity and Capital Resources."
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 earnings, if any, 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. 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. To the extent that
capitalized costs in the 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
write-down of oil and gas properties is not reversible at a later date even if
oil or gas prices increase.
In March 1995, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of "
("FAS 121"). As the Company utilizes the full cost method of accounting for
its exploration and development costs, it is required to calculate impairment
losses for its oil and gas properties using a cost center ceiling specified by
the Securities and Exchange Commission regulations for full cost companies.
The adoption of FAS 121 does not have an impact on the Company's financial
position or results of operations.
12
<PAGE> 15
In October 1995, the FASB issued Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"),
which encourages, but does not require, all entities to record compensation
expense on all stock-based compensation plans based upon fair value. The
Company continues to account for its stock-based compensation plans using the
accounting prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees." In accordance with FAS 123 the
Company has disclosed pro forma net income and earnings per share as if the
fair value-based method of accounting had been applied. See Note 6 to the
Company's financial statements.
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,
--------------------------------
1996 1995 1994
------- -------- -------
<S> <C> <C> <C>
Production:
Oil and condensate (MBbls) . . . . . . . . . . . . . . . . . . . . . . . 2,558 2,071 1,394
Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,323 33,719 24,267
Total production (MMcfe) . . . . . . . . . . . . . . . . . . . . . . . . 56,670 46,145 32,631
Average Realized Price:
Oil and condensate (per Bbl) . . . . . . . . . . . . . . . . . . . . . . $ 20.89 $ 17.23 $ 15.73
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.32 1.75 1.97
Average Costs (per Mcfe):
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.30 $ 0.31 $ 0.29
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . 1.13 1.08 1.05
General and administrative, net . . . . . . . . . . . . . . . . . . . . . 0.13 0.12 0.12
</TABLE>
1996 COMPARED TO 1995
PRODUCTION. Net production increased 23%, from 46.1 billion cubic
feet of natural gas equivalent ("Bcfe") for 1995, to 56.7 Bcfe for 1996. Oil
and condensate production for 1996 increased 487 thousand barrels ("MBbls"), or
24%, compared to 1995. Increased oil production for 1996 was due primarily to
production increases at Eugene Island 182, Ship Shoal 157 and the acquisition
of Ship Shoal 69 in the third quarter of 1996. Gas production increased by 7.6
billion cubic feet ("Bcf"), or 23%, from 33.7 Bcf for 1995 to 41.3 Bcf for
1996. Increased gas production was due to production increases at Eugene
Island 251/262 and production from wells drilled and placed on production at
Vermilion 355 and Vermilion 297 during the fourth quarter of 1995 and the first
quarter of 1996, respectively. These increases were partially offset by
natural production decline on other properties of the Company.
OIL AND GAS REVENUES. Oil and gas revenues for 1996 increased by
$54.7 million, or 58%, compared to 1995, primarily as a result of increased oil
and gas production and increased oil and gas prices. The average realized
price of oil and condensate increased by 21% and the average realized price of
natural gas increased by 33%.
13
<PAGE> 16
For the year ended December 31, 1996, the average realized gas price
was $2.32 per thousand cubic feet ("Mcf"), which, as a result of hedging
activities, was 86% of the $2.70 per Mcf average gas sales price that would
have otherwise been received. For the year ended December 31, 1995, the
average realized gas price was $1.75 per Mcf, which as a result of hedging
activities, was 105% of the $1.67 per Mcf average gas sales price that would
have otherwise been received. For 1996, the average realized oil and
condensate price was $20.89, which, as a result of hedging activities, was 99%
of the $21.15 per barrel average oil and condensate sales price that would have
otherwise been received. Oil hedging activities for 1995 had a negligible
impact on oil and condensate revenues. During 1996, approximately 54% of the
Company's equivalent production was subject to hedge positions as compared to
42% in 1995.
LEASE OPERATING EXPENSE. Lease operating expense for 1996 increased
to $16.9 million from $14.2 million for 1995. Despite a general increase in
costs in the oil service industry, lease operating expense per Mcf equivalent
("Mcfe") decreased from $0.31 for 1995, to $0.30 for 1996. The decrease in
lease operating expense per unit is primarily attributable to higher production
volumes.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. During 1996,
depreciation, depletion and amortization expense increased to $64.0 million
from $49.9 million for 1995. 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. The depletion
rate per unit for 1996 increased to $1.13 per Mcfe from $1.08 per Mcfe for
1995. The increase in the depletion rate per unit is primarily attributable to
higher cost reserve additions associated with proved properties the Company
acquired in 1996.
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 $7.6 million, or $0.13 per Mcfe,
for 1996 as compared to $5.5 million, or $0.12 per Mcfe, for 1995. Performance
based compensation, as a component of general and administrative expense,
increased from $2.4 million, or $0.05 per Mcfe, for 1995, to $4.9 million, or
$0.09 per Mcfe, for 1996. Direct costs associated with staff increases during
1996 were offset to a significant extent 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 continue to increase.
STOCK COMPENSATION EXPENSE. Stock compensation expense increased by
$1.3 million during 1996 due to the amortization of additional noncash
compensation expense associated with 246,000 shares of restricted stock that
were granted in 1996 to employees and 10,000 shares of restricted stock that
were granted to non-employee Directors.
NET INCOME. As a result of the foregoing, the Company had net income
of $38.5 million or $1.03 for 1996, as compared to $16.3 million or $0.45 per
share for 1995.
1995 COMPARED TO 1994
PRODUCTION. Net production increased 41%, from 32.6 Bcfe in 1994 to
46.1 Bcfe for 1995. During 1995, gas production increased by 9.5 Bcf, or 39%,
to 33.7 Bcf from 24.3 Bcf for the year 1994. Increased gas production was due
to production increases at Eugene Island 182, the acquisition of South
Timbalier 100 in the second quarter of 1995, and wells drilled and placed on
production during the first quarter of 1995 at Eugene Island 251/262, Main Pass
255/259 and Vermillion 288. These increases were partially offset by natural
production decline on other properties of the Company. Oil and condensate
production for 1995 increased 677 MBbls, or 49%, compared to 1994. Increased
oil and condensate production for 1995 was due primarily to initial production
in 1995 following development drilling during 1994 at Eugene Island 182 and
Eugene Island 251/262.
14
<PAGE> 17
OIL AND GAS REVENUES. Oil and gas revenues for 1995 increased by
$24.9 million, or 36%, compared to 1994. The increase was primarily the result
of increased oil and gas production and increased oil and condensate prices,
partially offset by a decrease in gas prices. The average realized price of
oil and condensate increased by 10% and the average realized price of natural
gas decreased by 11%.
As a result of hedging activities for gas production for 1995, the
Company realized an average gas price of $1.75 per Mcf, or 105% of the $1.67
per Mcf average gas sales price that otherwise would have been received. For
1994, the average realized gas price was $1.97, which, as a result of hedging
activities, was 102% of the $1.94 per Mcf average gas sales price that would
have otherwise been received. The hedging activities for oil and condensate
production for 1995 had a negligible impact on oil and condensate revenues.
There were no hedging activities for oil and condensate production in 1994.
During 1995, approximately 42% of the Company's equivalent production was
subject to hedge positions as compared to 16% in 1994.
LEASE OPERATING EXPENSE. Lease operating expense for 1995 increased
$4.6 million to $14.2 million from $9.6 million for 1994. Lease operating
expense per Mcfe increased from $0.29 for 1994 to $0.31 for 1995. Both
increases are primarily attributable to lease operating costs associated with
properties the Company acquired during the first half of 1995, with the
increase per Mcfe partially offset by higher production volumes.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE. In 1995,
depreciation, depletion and amortization expense increased to $49.9 million
from $34.1 million in 1994. The increase is attributable to an increased
depletion rate per Mcfe and increased production volumes in 1995 as compared to
1994. The depletion rate for 1995 increased to $1.08 per Mcfe from $1.05 per
Mcfe for 1994.
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 $5.5 million for 1995 as compared
to $3.8 million for 1994. Direct costs associated with staff increases since
the end of 1994 were offset to a significant extent by program and joint
interest reimbursements.
NET INCOME. As a result of the foregoing, the Company had net income
of $16.3 million, or $0.45 per share, for 1995, an increase of $1.8 million
compared to $14.4 million, or $0.40 per share, for 1994.
LIQUIDITY AND CAPITAL RESOURCES
The Company had $11.4 million of working capital at December 31, 1996
compared to $11.2 million at December 31, 1995. Historically, the Company has
funded its oil and gas activities through cash flow from operations, equity
capital from private and public sources and bank borrowings.
From time to time, the Company has utilized 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 productionis delivered.
15
<PAGE> 18
The following is a summary of the Company's natural gas hedge positions as of
January 1, 1997.
<TABLE>
<CAPTION>
MONTHLY
VOLUME WEIGHTED AVERAGE
PERIOD IN Bcf SALES POINT PRICE PER Mcf (1)
----------------------- -------- --------------------------------
COLLAR
-------------------
SWAP FLOOR CEILING
--------- -------- ---------
<S> <C> <C> <C> <C>
January 1997 - March 1997
Price Swap Contracts 1.30 $ 2.36 - -
Cashless Collar Contracts 1.25 - $ 2.22 $ 2.67
Cashless Collar Contracts 1.30 - $ 2.76 $ 3.25
April 1997 - June 1997
Price Swap Contracts 0.80 $ 2.08 - -
</TABLE>
- -------------------------------
(1) Price per Mcf is based upon the average energy content of the
Company's gas production for the twelve months ended December 31,
1996.
These gas hedging transactions are settled based on reported sales
prices of natural gas delivered into those pipelines at the physical locations
where the Company sells its production (the "Sales Point Price"). Because
substantially all of the Company's natural gas production is sold under spot
contracts that reference to the Sales Point Price, the Company has no basis
risk with respect to these transactions. See Note 2 to the Company's financial
statements.
The Company maintains a $125 million reserve-based revolving credit
facility with the Chase Manhattan Bank, N.A., as agent. The credit agreement
provides for a revolving credit period through June 30, 1998, at which time the
aggregate loans outstanding under the credit agreement convert to a term loan
with quarterly maturities through June 30, 2001. As of December 31, 1996, the
borrowing base was $125 million, of which $60 million was outstanding.
The Company's net cash flow from operations for 1996 was $127.5
million compared to $67.6 million for 1995. Net cash flow from operations
before changes in operating assets and liabilities for 1996 was $125.2 million
compared to $75.6 million for 1995. The year-to-year increase in net cash flow
from operations before changes in operating assets and liabilities is primarily
attributable to increases in oil and gas production and higher average realized
natural gas and oil prices, partially offset by higher operating expenses.
Capital expenditures for 1996 were $163.8 million, consisting of $49.3
million for exploration, $80.3 million for development and $34.2 million for
acquisitions of properties. The Company's exploration capital expenditure
budget for 1997 is approximately $67 million. Primarily as a result of the
Company's successful exploratory wells drilled in 1996, 16% of the Company's
proved reserves at December 31, 1996 were proved undeveloped. The Company has
budgeted approximately $81 million in 1997 for development drilling and
construction expenditures for platforms, facilities and pipelines. No
significant abandonment or dismantlement costs are anticipated during 1997.
The Company continues to pursue attractive acquisition opportunities. The
timing and size of any acquisition and the associated capital commitments are
unpredictable.
16
<PAGE> 19
Actual levels of capital expenditures may vary significantly due to
many factors, including drilling results, oil and gas prices, industry
conditions, the prices 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 1996, the Company borrowed $281 million and repaid
$251 million under the credit facility. The Company anticipates additional
borrowings under this facility during 1997.
To cover the various obligations of lessees on the Outer Continental
Shelf (the "OCS"), the United States Department of the Interior Minerals
Management Service (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.
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 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 and
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, results of operations or
cash flows of the Company.
17
<PAGE> 20
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.
/s/ JOE B. FOSTER /s/ TERRY W. RATHERT
Joe B. Foster Terry W. Rathert
Chairman of the Board, President Vice President, Chief
and Chief Executive Officer Financial Officer and
Secretary
18
<PAGE> 21
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of
Newfield Exploration Company:
We have audited the accompanying balance sheets of Newfield
Exploration Company as of December 31, 1996 and 1995, and the related
statements of income, stockholders' equity and cash flows for each of the three
years in the period ended December 31, 1996. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Newfield
Exploration Company as of December 31, 1996 and 1995, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
/s/ COOPERS & LYBRAND L.L.P.
Coopers & Lybrand L.L.P.
Houston, Texas
February 11, 1997
19
<PAGE> 22
NEWFIELD EXPLORATION COMPANY
BALANCE SHEET
(In thousands of dollars, except share data)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1996 1995
--------- ---------
ASSETS
------
<S> <C> <C>
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . $ 13,290 $ 12,533
Accounts receivable - oil and gas . . . . . . . . . . . . . . . . . . . . 46,814 25,332
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,179 4,952
--------- ---------
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . 61,283 42,817
--------- ---------
Oil and gas properties (full cost method, of which $55,305
at December 31, 1996 and $19,517 at December 31, 1995
were excluded from amortization) . . . . . . . . . . . . . . . . . . . . . 526,680 362,857
Furniture, fixtures and equipment . . . . . . . . . . . . . . . . . . . . . . 2,496 1,806
Less - accumulated depreciation, depletion and amortization . . . . . . . . . (199,161) (135,148)
--------- ---------
330,015 229,515
--------- ---------
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,640 5,074
--------- ---------
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 395,938 $ 277,406
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . $ 46,072 $ 24,487
Advances from joint owners . . . . . . . . . . . . . . . . . . . . . . . . 3,612 1,673
Current maturities of capital lease obligations . . . . . . . . . . . . . 163 422
Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . --- 5,000
--------- ---------
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . 49,847 31,582
--------- ---------
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,048 1,060
Long-term capital lease obligations . . . . . . . . . . . . . . . . . . . . . --- 152
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,000 25,000
Deferred taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44,141 26,041
--------- ---------
Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . 106,189 52,253
--------- ---------
Commitments and contingencies (Note 5) . . . . . . . . . . . . . . . . . . . --- ---
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000 shares authorized;
no shares issued) . . . . . . . . . . . . . . . . . . . . . . . . . . . --- ---
Common stock ($0.01 par value, 50,000,000 shares authorized;
35,243,040 and 34,354,844 shares issued and outstanding
at December 31, 1996 and December 31, 1995, respectively) . . . . . . . 352 343
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . 147,291 137,830
Unearned compensation . . . . . . . . . . . . . . . . . . . . . . . . . . (2,746) (1,113)
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95,005 56,511
--------- ---------
Total stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . 239,902 193,571
--------- ---------
Total liabilities and stockholders' equity . . . . . . . . . . . . . . . $ 395,938 $ 277,406
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
20
<PAGE> 23
NEWFIELD EXPLORATION COMPANY
STATEMENT OF INCOME
(In thousands, except share and per share data)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Oil and gas revenues . . . . . . . . . . . . . . . . . . . . . . . $ 149,256 $ 94,598 $ 69,728
--------- --------- ---------
Operating expenses:
Lease operating . . . . . . . . . . . . . . . . . . . . . . . 16,946 14,227 9,555
Depreciation, depletion and amortization . . . . . . . . . . . 64,026 49,904 34,118
General and administrative, net . . . . . . . . . . . . . . . 7,552 5,549 3,802
Stock compensation . . . . . . . . . . . . . . . . . . . . . . 1,943 692 1,084
--------- --------- ---------
Total operating expenses . . . . . . . . . . . . . . . . . 90,467 70,372 48,559
--------- --------- ---------
Income from operations . . . . . . . . . . . . . . . . . . . . . . 58,789 24,226 21,169
Other income (expenses):
Interest income . . . . . . . . . . . . . . . . . . . . . . . 917 988 1,742
Interest expense, net . . . . . . . . . . . . . . . . . . . . (420) (208) (363)
--------- --------- ---------
497 780 1,379
--------- --------- ---------
Income before income taxes . . . . . . . . . . . . . . . . . . . . 59,286 25,006 22,548
Income tax provision:
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 21 453
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,763 8,721 7,655
--------- --------- ---------
20,792 8,742 8,108
--------- --------- ---------
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 38,494 $ 16,264 $ 14,440
========= ========= =========
Earnings per common share . . . . . . . . . . . . . . . . . . . . . $ 1.03 $ 0.45 $ 0.40
========= ========= =========
Weighted average number of shares and common stock
equivalents outstanding . . . . . . . . . . . . . . . . . . . . . . 37,202,545 36,193,102 35,910,348
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
21
<PAGE> 24
NEWFIELD EXPLORATION COMPANY
STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(In thousands, except share data)
<TABLE>
<CAPTION>
UNREALIZED GAIN (LOSS)
COMMON STOCK ADDITIONAL ON INVESTMENT TOTAL
------------------ PAID-IN UNEARNED RETAINED SECURITIES STOCKHOLDERS
SHARES AMOUNT CAPITAL COMPENSATION EARNINGS AVAILABLE FOR SALE EQUITY
--------- ------ --------- ------------ -------- ------------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993 . . . . 33,098,710 $ 331 $ 129,579 $ (2,872) $ 25,807 $ 152,845
Issuance of common stock
for cash, net of offering costs . 233,650 2 1,139 1,141
Amortization of stock
compensation . . . . . . . . . . 1,084 1,084
Unrealized loss on investment
securities available for sale
($30 loss, net of deferred income
taxes of $11) . . . . . . . . . . $ (19) (19)
Net income . . . . . . . . . . 14,440 14,440
---------- ------ --------- ------------ -------- ------- -----------
Balance, December 31, 1994 . . . . 33,332,360 333 130,718 (1,788) 40,247 (19) 169,491
Issuance of common stock
for cash, net of offering costs . 1,016,484 10 4,333 4,343
Issuance of restricted stock, less
amortization of $33 . . . . . . . 6,000 80 (47) 33
Cancellation of stock options . . . (63) 17 (46)
Amortization of stock
compensation . . . . . . . . . . 705 705
Adjustment to unrealized loss
on investment securities
available for sale . . . . . . . 19 19
Tax benefit from exercise
of stock options (Note 6) . . . . 2,762 2,762
Net income . . . . . . . . . . 16,264 16,264
---------- ------ --------- ------------ -------- ------- -----------
Balance, December 31, 1995 . . . . 34,354,844 343 137,830 (1,113) 56,511 --- 193,571
Issuance of common stock
for cash . . . . . . . . . . 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
========== ===== ========= ========== ========= ======== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
22
<PAGE> 25
NEWFIELD EXPLORATION COMPANY
STATEMENT OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Cash flows from operating activities:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 38,494 $ 16,264 $ 14,440
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization . . . . . . . . . 64,026 49,904 34,118
Deferred taxes . . . . . . . . . . . . . . . . . . . . . . 20,763 8,721 7,655
Stock compensation . . . . . . . . . . . . . . . . . . . . 1,943 692 1,084
Realized loss on sale of investment securities . . . . . . --- 32 238
---------- ---------- ---------
125,226 75,613 57,535
Changes in assets and liabilities:
(Increase) decrease in accounts receivable,
oil and gas . . . . . . . . . . . . . . . . . . . . . (21,418) (8,859) 5,425
(Increase) decrease in other current assets . . . . . . . 3,793 (307) 1,218
(Increase) decrease in other assets . . . . . . . . . . . 443 (24) (1,226)
Increase in accounts payable
and accrued liabilities . . . . . . . . . . . . . . . 16,523 4,275 718
Increase (decrease) in advances from joint owners . . . 1,939 (3,194) 4,357
Increase in other liabilities . . . . . . . . . . . . . . 988 136 94
---------- ---------- ---------
Net cash provided by operating activities . . . . . 127,494 67,640 68,121
---------- ---------- ---------
Cash flows from investing activities:
Additions to oil and gas properties . . . . . . . . . . . . (158,834) (106,957) (114,892)
Additions to furniture, fixtures and equipment . . . . . . . (703) (599) (229)
Purchases of investment securities . . . . . . . . . . . . . --- --- (40,997)
Sales of investment securities . . . . . . . . . . . . . . . --- 8,227 32,499
---------- ---------- ---------
Net cash used in investing activities . . . . . . . (159,537) (99,329) (123,619)
---------- ---------- ---------
Cash flows from financing activities:
Proceeds from borrowings . . . . . . . . . . . . . . . . . . 281,000 96,000 ---
Repayments of borrowings . . . . . . . . . . . . . . . . . . (251,000) (66,000) ---
Proceeds from issuances of common stock, net . . . . . . . . 3,210 4,343 1,141
Payments on capital lease obligations . . . . . . . . . . . (410) (533) (276)
---------- ---------- ---------
Net cash provided by financing activities . . . . . 32,800 33,810 865
---------- ---------- ---------
Increase (decrease) in cash and cash equivalents . . . . . . . 757 2,121 (54,633)
Cash and cash equivalents, beginning of period . . . . . . . . 12,533 10,412 65,045
---------- ---------- ---------
Cash and cash equivalents, end of period . . . . . . . . . . . $ 13,290 $ 12,533 $ 10,412
========== ========== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
23
<PAGE> 26
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
These financial statements include the accounts of Newfield
Exploration Company (the "Company"), a Delaware corporation, which was formed
on December 5, 1988 to conduct offshore oil and gas exploration and drilling
and development operations in the Gulf of Mexico. 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 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.
Common Stock Split
On December 1, 1996 the Company's Board of Directors declared a
two-for-one split of its outstanding common stock to stockholders of record on
December 16, 1996. The stated par value per share of common stock was not
changed from $0.01. These financial statements and notes thereto have been
restated to retroactively reflect the stock split.
Earnings Per Share
Net income per share is calculated by dividing net income by the
weighted average shares of Common Stock and Common Stock equivalents
outstanding.
Cash Flow Statement
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. Cash flows resulting from oil and
gas sales hedging contracts are classified in the same category as the items
being hedged.
24
<PAGE> 27
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
Stock-Based Compensation
In October 1995, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation" ("FAS 123"), which encourages, but does not require,
all entities to record compensation expense on all stock-based compensation
plans based upon fair value. The Company continues to account for its
stock-based compensation plans using the accounting prescribed by Accounting
Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to
Employees." In accordance with FAS 123 the Company has disclosed pro forma net
income and earnings per share as if the fair value-based method of accounting
had been applied. See Note 6.
Fair Value of Financial Instruments
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.
Oil and Gas Properties
The Company uses the full cost method of accounting for exploration
and development costs. Under this method of accounting, all costs incurred in
the acquisition, exploration and development of oil and gas properties are
capitalized. Such capitalized costs and estimated future development and
dismantlement costs are amortized on a unit-of-production method based on
proved reserves. 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.
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. At December 31, 1995, the Company had $3.5 million included in
other current assets which was a receivable from an industry investor relating
to its participation in the acquisition of an overriding royalty interest.
Unevaluated properties and associated costs not currently being
amortized and included in oil and gas properties were $55.3 million and $19.5
million at December 31, 1996 and 1995, respectively. The properties
represented by these costs were at such dates undergoing exploration or
development 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, 1996 will be substantially evaluated and
therefore subject to amortization in 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.
25
<PAGE> 28
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
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 specific 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.
Total estimated future abandonment and dismantlement costs associated
with the Company's developed and acquired properties were $41.5 million, $35.9
million, and $26.0 million as of December 31, 1996, 1995 and 1994,
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 $18.0 million,
$13.7 million and $8.4 million as of December 31, 1996, 1995 and 1994,
respectively.
Production Imbalances
Joint interest owners may take more or less than their ownership
interest of natural gas volumes from jointly owned reservoirs. The Company
follows the sales method of accounting for imbalances. Under this method, the
Company records a liability if its sales of gas volumes in excess of its
entitlements from a jointly owned reservoir exceed its interest in the
remaining estimated gas reserves of such reservoir. Imbalances are monitored
to minimize significant imbalances, and such imbalances were not significant at
December 31, 1996 and December 31, 1995.
Income Taxes
The Company follows Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("FAS 109"). This statement requires
deferred tax assets and liabilities to be 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, which
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.
26
<PAGE> 29
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
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, 1996, to Gulfmark
Energy, Inc. (17%), Coast Energy Group (16%), and Superior Natural Gas
Corporation (12%); for the year ended December 31, 1995, to Gulfmark Energy,
Inc. (22%), Coast Energy Group (15%), and Northridge Energy (10%); for the year
ended December 31, 1994, to Coast Energy Group (14%), Gulfmark Energy, Inc.
(14%), and Eagle Natural Gas Company (12%). Based upon the current demand for
oil and gas, the Company believes that the loss of any of these purchasers
would not have a material adverse effect on the Company.
2. FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK:
From time to time, the Company has utilized 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.
During 1996, approximately 54% of the Company's equivalent production
was subject to hedge positions as compared to 42% in 1995. The Company has
also entered into hedging transactions with respect to a portion of its
estimated production for 1997. The Company continues to evaluate whether to
enter into additional hedging transactions for 1997 and future years. In
addition, the Company may determine from time to time to terminate its then
existing hedging positions. The following is a summary of the Company's
natural gas hedge positions as of December 31, 1996.
<TABLE>
<CAPTION>
MONTHLY FAIR
VOLUME WEIGHTED AVERAGE MARKET
PERIOD IN Bcf SALES POINT PRICE PER Mcf (1) VALUE (2)
------------------------- -------- ------------------------------ -----------------
COLLAR
------------------
SWAP FLOOR CEILING
---- ----- -------
<S> <C> <C> <C> <C> <C>
January 1997 - March 1997
Price Swap Contracts 1.30 $ 2.36 --- --- ($3.3 million)(3)
Cashless Collar Contracts 1.25 --- $ 2.22 $ 2.67 ($2.3 million)(3)
Cashless Collar Contracts 1.30 --- $ 2.76 $ 3.25 ($1.0 million)(3)
April 1997 - June 1997
Price Swap Contracts 0.80 $ 2.08 --- --- ($0.2 million)(3)
</TABLE>
- ----------------
(1) Price per Mcf is based upon the average energy content of the
Company's gas production for the twelve months ended December 31,
1996.
(2) The fair market value is calculated using prices derived from NYMEX
futures contract prices existing at December 31, 1996.
(3) This opportunity loss will be substantially offset in the cash market
when the hedged production is delivered in 1997, which has the effect
of fixing the price at which the commodity is sold.
27
<PAGE> 30
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
These gas swaps are settled based on published sales prices of natural
gas delivered into pipelines at the locations where the Company sells its
production, (the "Sales Point Price"). With respect to any particular swap
transaction, the counterparty is required to make a payment to the Company in
the event that the average Sales Point 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 average Sales Point 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 average Sales Point Price for the reference
period is below the floor price for such transaction, and the Company is
required to make payment to the counterparty if the average Sales Point Price
for the reference period is above the ceiling price for such transaction.
Because substantially all of the Company's natural gas production is sold under
spot contracts that reference Sales Point Price, the Company has no basis risk
with respect to these transactions.
3. DEBT:
The Company has an unsecured revolving credit agreement with a current
commitment of $125 million ("Aggregate Commitment"). As of December 31, 1996,
there was $60 million outstanding under this credit agreement and the Company's
available borrowing base was $125 million ("Borrowing Base"). The Borrowing
Base is determined by the majority banks party to the agreement on May 1 and
November 1 of each year. Available funds under the agreement are established
quarterly by the Company (the "Designated Borrowing Base"). The Designated
Borrowing Base is an amount greater than or equal to the Designated Borrowing
Base Floor Amount of $75 million but less than or equal to the Borrowing Base.
As of December 31, 1996 the Company's Designated Borrowing Base was $75
million. The Company retains the ability, subject to notification, to increase
the Designated Borrowing Base to an amount not to exceed the Borrowing Base.
Borrowings under the credit agreement bear interest, payable
quarterly, at the Company's option at (i) the higher of (a) the federal fund
rate (5.25% at December 31, 1996) plus 50 basis points and (b) the bank's prime
rate (8.25% at December 31, 1996), plus a variable margin, which ranges up to
25 basis points based upon the loan amount outstanding relative to the
borrowing base, or (ii) LIBOR (30 day LIBOR was 5.50% at December 31, 1996),
plus a variable margin, which ranges from 75 to 125 basis points based upon the
loan amount outstanding relative to the borrowing base. The credit agreement
also provides for a commitment fee, to be paid quarterly, of 37.5 basis points
per annum on the unused Designated Borrowing Base available to the Company. In
addition, a standby fee, to be paid quarterly, of 12.5 basis points per annum
will be paid on the difference between the Designated Borrowing Base and the
Aggregate Commitment. The Company paid commitment fees of approximately
$205,000, $179,000 and $100,000 for the years ended December 31, 1996, 1995 and
1994, respectively.
The credit agreement provides for a revolving credit period through
June 30, 1998, at which time the aggregate loans outstanding under the credit
agreement convert to a term loan with quarterly maturities through June 30,
2001.
The credit agreement contains positive and negative covenants, which,
among other things, require the Company to maintain a working capital ratio, as
defined, of at least 1.1 to 1.0, a fixed charge coverage ratio, as defined, of
at least 1.5 to 1.0 and a minimum net worth. The credit agreement also limits
the incurrence of additional debt, additional liens on properties, sale of
certain assets and the declaration or payment of dividends.
28
<PAGE> 31
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
4. FEDERAL INCOME TAXES:
The components of deferred tax assets and liabilities pursuant to FAS
109 are as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1996 1995
--------- ---------
<S> <C> <C>
Deferred tax liability:
Oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . $ 55,993 $ 35,059
--------- ---------
Deferred tax asset:
Alternative minimum tax . . . . . . . . . . . . . . . . . . . . . . . 1,848 1,846
Net operating losses . . . . . . . . . . . . . . . . . . . . . . . . . 8,329 5,567
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,675 1,605
--------- ---------
11,852 9,018
Valuation Allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . --- ---
--------- ---------
Net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . $ 44,141 $ 26,041
========= =========
</TABLE>
The Company does not believe a deferred tax asset valuation is
required because all tax carryovers are expected to be fully utilized.
As of December 31, 1996, the Company had a net operating loss ("NOL")
carryforward for federal income tax purposes of approximately $23.8 million
that may be used in future years to offset taxable income. Utilization of the
Company's NOL carryforward is subject to annual limitations due to certain
stock ownership changes that have occurred or may occur. To the extent not
utilized, the NOL carryforward will begin to expire in 2005.
5. COMMITMENTS AND CONTINGENCIES:
The Company has entered into a noncancelable operating lease agreement
for office space in Houston, Texas. The lease term expires in November 2002,
with two options to renew the lease for five years each.
Future minimum lease payments required as of December 31, 1996 related
to this operating lease are as follows (in thousands):
Year ended December 31,
<TABLE>
<S> <C>
1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 553
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 572
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 592
2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 613
2001 and thereafter . . . . . . . . . . . . . . . . . . . . . . 1,174
-------
Total minimum lease payments . . . . . . . . . . . . . . . $ 3,504
=======
</TABLE>
Rent expense for the years ended December 31, 1996, 1995 and 1994 was
$537,000, $490,000 and $464,000, 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 and results of operations of
the Company.
29
<PAGE> 32
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
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. In
October 1995, the FASB issued Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation" ("FAS 123"), which encourages,
but does not require, all entities to record compensation expense on all
stock-based compensation plans based upon fair value. The Company continues to
account for its stock-based compensation plans using the accounting prescribed
by APB Opinion No. 25. However, pro forma disclosures as if the Company
adopted the cost recognition provisions of FAS 123 in 1995 are presented below.
Stock Option Plans
The Company has granted options pursuant to its 1989, 1990, 1991, 1993
and 1995 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 based on the
number of full years the options are held from the date of grant. At December
31, 1996, a total of 3,482,700 options were outstanding, of which 2,168,770
were exercisable. At such date, the Company had an additional 1,022,600
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 following is a summary of all
stock option activity for 1994, 1995 and 1996:
<TABLE>
<CAPTION>
NUMBER WEIGHTED
OF SHARES OF AVERAGE
UNDERLYING EXERCISE
OPTIONS PRICES
--------- ---------
<S> <C> <C>
Outstanding at December 31, 1993 . . . . . . . . . 4,450,940 $ 4.01
Granted . . . . . . . . . . . . . . . . . . . . . 196,000 12.90
Exercised . . . . . . . . . . . . . . . . . . . . (199,500) 4.28
Expired . . . . . . . . . . . . . . . . . . . . . (9,000) 4.00
--------- ---------
Outstanding at December 31, 1994 . . . . . . . . . 4,438,440 4.39
Granted . . . . . . . . . . . . . . . . . . . . . 241,600 13.18
Exercised . . . . . . . . . . . . . . . . . . . . (981,550) 4.06
Forfeited . . . . . . . . . . . . . . . . . . . . (34,750) 9.63
Expired . . . . . . . . . . . . . . . . . . . . . (96,000) 14.14
--------- ---------
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
========= =========
Exercisable at December 31, 1994 . . . . . . . . . 2,527,940 $ 3.94
========= =========
Exercisable at December 31, 1995 . . . . . . . . . 2,292,790 $ 4.04
========= =========
Exercisable at December 31, 1996 . . . . . . . . . 2,168,770 $ 4.18
========= =========
</TABLE>
The weighted average fair value of options granted during 1996 and 1995 was
$6.39 and $5.69, respectively.
30
<PAGE> 33
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
The fair value of each stock option granted during 1996 and 1995 was
estimated as of the date of grant using the Black-Scholes option-pricing model
with the following weighted-average assumptions for grants in 1996 and 1995: no
dividend yield; expected volatility of 28.52%; risk-free interest rates ranging
from 5.33% to 6.71%; and an expected option life of 6.50 years.
The following table summarizes information about stock options
outstanding and exercisable at December 31, 1996:
<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> <C>
$ 3.50 to $ 5.62 2,690,930 5 years $ 4.00 2,116,930 $ 3.97
10.94 to 14.78 700,770 9 years 13.50 51,840 12.82
17.47 to 25.50 91,000 10 years 22.28 --- --
------------------- ----------- ---------------- -------------- ----------- --------------
$ 3.50 to $ 25.50 3,482,700 6 years $ 6.39 2,168,770 $ 4.18
</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 1996 and
1995 resulted in a tax benefit to the Company of approximately $2.7 million and
$2.8 million, respectively, which was recorded as an increase in stockholders'
equity.
Restricted Stock
The Company has adopted two plans pursuant to which restricted shares
of Common Stock may be granted. Under the Newfield Exploration Company 1995
Omnibus Stock Plan ("the 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 Omnibus Plan. In 1996 the Company issued 246,000 shares of restricted
Common Stock whose shares vest at the rate of 20% per year on each anniversary
of the date of issuance, commencing on the first anniversary date of issuance
subject to the lapse of certain performance-based forfeiture provisions.
Under the Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan ("the Non-Employee Director Plan"), the Company may grant
to "Non-Employee Directors" up to 50,000 shares of Common Stock as restricted
Common Stock. The Non-Employee Director Plan provides for the automatic,
nondiscretionary issuance of 1,000 shares of restricted Common Stock to each
director when first elected to the Company's board of directors, whose shares
vest at the rate of 33-1/3% per year on the day before the first, second and
third annual shareholder meetings following the date the shares were issued.
The Company issued 10,000 shares to five Non-Employee Directors in 1996 and
6,000 shares to three Non-Employee Directors in 1995.
31
<PAGE> 34
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
In accordance with APB Opinion No. 25, upon the issuance of restricted
shares of Common Stock under these two plans, the Company recognized a
compensation cost for the cost of the restricted Common Stock in the amount of
$3.6 million for 1996 and $80,000 for 1995. This cost is charged to
shareholders' equity and recognized as amortization expense over the applicable
vesting period, in the amount of $1.5 million for 1996 and $32,000 for 1995.
The weighted average exercise price for 256,000 shares of restricted Common
Stock issued in 1996 is $14.08. The weighted average exercise price for 6,000
shares of restricted Common Stock issued in 1995 is $13.28.
Employee Stock Purchase Plan
During 1993, 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 to its full-time (or part-time for at least 20
hours per week and at least five months per year) employees at a discount from
the stock's fair market value through payroll deductions.
For each six-month period beginning on January 1 or July 1 during the
term of the Stock Purchase Plan, unless the Board determines otherwise, each
eligible employee has the opportunity to purchase Common Stock through
voluntary payroll deductions. Employees make an election to participate prior
to the start of a period by stating the percentage of their compensation to be
withheld. An employee may have withheld from two to ten percent of the
employee's base wages or salary. The Stock Purchase Plan allows withdrawals,
terminations and reductions on the amounts being deducted. The purchase price
for the Common Stock will be 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 23,990 shares and
25,946 shares to employees in 1996 and 1995, respectively, which had weighted
average exercise prices of $13.56 and $9.78, respectively. The weighted
average fair market value of the shares sold during 1996 and 1995 was $1.92 and
$1.86, respectively. In accordance with APB Opinion No. 25, the Company has
not recognized any compensation cost for the Stock Purchase Plan.
The fair value of each stock 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 1996 and
1995, respectively: no dividend yield for both years; expected volatility of
28.52% for both years; risk-free interest rates ranging from 5.07% to 6.11%;
and expected lives of six months for both years.
Pro Forma Net Income and Net Income Per Common Share
Pursuant to APB Opinion No. 25, the Company recognized a charge of
$1.5 million as compensation expense for equity-based compensation awarded in
1996 and $32,000 as compensation expense for equity-based compensation awarded
in 1995. If the fair value based method of accounting in FAS 123 had been
applied, the Company would have recognized $2.3 million in 1996 and $197,000 in
1995 as compensation expense.
32
<PAGE> 35
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
The Company's net income and earnings per common share for 1996 and
1995 would have approximated the pro forma amounts below (in thousands except
per share data):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1996 1995
--------- ----------
<S> <C> <C>
Net Income - as reported . . . . . . . . . . . . . . . . $ 38,494 $ 16,264
Net Income - pro forma . . . . . . . . . . . . . . . . . $ 37,956 $ 16,140
Earnings per common share - as reported . . . . . . . . $ 1.03 $ 0.45
Earnings per common share - pro forma . . . . . . . . . $ 1.02 $ 0.45
</TABLE>
The effects of applying FAS 123 in this pro forma disclosure are not
indicative of future amounts. FAS 123 does not apply to awards prior to 1995,
and the Company anticipates making awards in the future under its stock-based
compensation plans.
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 $371,000, $301,000 and
$112,000 for the years ended December 31, 1996, 1995 and 1994, 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. Current awards are
distributed to employees by March 1 of the year following the performance
period, with the deferred amounts being distributed in four equal payments on
each following December 1. 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 shall be 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, 1996 and 1995 were $4.9 million and $2.4 million,
respectively.
33
<PAGE> 36
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
8. RELATED PARTY TRANSACTIONS:
Warburg, Pincus Counsellors, Inc. (an affiliate of Warburg, Pincus &
Co., general partner of Warburg, Pincus Investors, L.P., a significant
stockholder of the Company) provided investment management and consulting
services for the Company for a fee. Such services included advice and
assistance concerning the investment and management of the Company's excess
funds invested in marketable securities. Payments for such services were
$39,000 for 1994. No such fees were incurred during 1995 and 1996.
The 401(k) Plan invests in several mutual funds (the "Warburg Funds")
affiliated with Warburg, Pincus & Co. 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 $1,314,000 and $1,077,000 as of December 31, 1996 and
1995, respectively.
9. SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for interest and income taxes for each of the three
years in the period ended December 31, 1996, are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Interest payments (net of interest capitalized of
$1,508, $674 and $217 during 1996, 1995
and 1994, respectively) . . . . . . . . . . . . . . . . . . . $ 363 $ 127 $ 29
Income tax payments . . . . . . . . . . . . . . . . . . . . . . . . . . $ --- $ 550 $ 200
</TABLE>
The following transactions have been appropriately excluded from the
statement of cash flows:
<TABLE>
<CAPTION>
1996 1995 1994
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Long-term capital leases . . . . . . . . . . . . . . . . . . . . . . . $ (73) $ 9 $ 700
Increase (decrease) in capital accrual . . . . . . . . . . . . . . . . $ 5,062 $ (22) $ 1,800
Changes in working capital amounts related to property acquisitions . . $ --- $ (2,750) $ ---
</TABLE>
34
<PAGE> 37
NEWFIELD EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
10. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
The results of operations by quarter for the years ended December 31,
1996 and 1995 are as follows (in thousands, except per share amounts):
<TABLE>
<CAPTION>
1996 QUARTER ENDED
-------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- -------- ------------ -----------
<S> <C> <C> <C> <C>
Oil and gas revenues . . . . . . . . . . . $ 32,962 $ 33,013 $ 35,799 $ 47,482
Income from operations . . . . . . . . . . 12,123 12,162 13,078 21,426
Net income . . . . . . . . . . . . . . 7,929 7,949 8,673 13,943
Earnings per common share . . . . . . . . . $ 0.22 $ 0.21 $ 0.23 $ 0.37
1995 QUARTER ENDED
-------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- -------- ------------ -----------
Oil and gas revenues . . . . . . . . . . . $ 19,029 $ 24,811 $ 24,622 $ 26,136
Income from operations . . . . . . . . . . 4,904 6,641 5,615 7,066
Net income . . . . . . . . . . . . . . 3,403 4,417 3,769 4,675
Earnings per common share . . . . . . . . . $ 0.09 $ 0.12 $ 0.10 $ 0.13
</TABLE>
35
<PAGE> 38
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 equipment 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, 1996 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
36
<PAGE> 39
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, 1996, as estimated by the
Company's petroleum engineering staff:
<TABLE>
<CAPTION>
OIL, CONDENSATE
AND NATURAL NATURAL
GAS LIQUIDS GAS
Proved developed and undeveloped reserves: (MBbls) (MMcf)
------- --------
<S> <C> <C>
December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,414 102,261
Revisions of previous estimates . . . . . . . . . . . . . . . . . . 127 (3,409)
Extensions, discoveries and other additions . . . . . . . . . . . . 2,845 53,900
Purchases of properties . . . . . . . . . . . . . . . . . . . . . . 618 25,482
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,394) (24,267)
------- --------
December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,610 153,967
Revisions of previous estimates . . . . . . . . . . . . . . . . . . 166 (575)
Extensions, discoveries and other additions . . . . . . . . . . . . 926 62,035
Purchases of properties . . . . . . . . . . . . . . . . . . . . . . 2,002 22,556
Sales of properties . . . . . . . . . . . . . . . . . . . . . . . . --- (684)
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,071) (33,719)
------- --------
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
======= ========
CRUDE NATURAL
OIL GAS
(MBbls) (MMcf)
------- --------
Proved developed reserves:
December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . . . . 8,196 140,742
December 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . 8,292 154,726
December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . 11,820 199,452
</TABLE>
37
<PAGE> 40
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 (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Proved properties $ 501,328 $ 348,226 $ 254,196
Unproved properties 25,352 14,631 4,476
----------- ---------- ----------
526,680 362,857 258,672
Accumulated depreciation, depletion and amortization (198,065) (134,348) (84,748)
----------- ---------- ----------
Net capitalized costs $ 328,615 $ 228,509 $ 173,924
=========== ========== ==========
</TABLE>
Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Property acquisition:
Unproved* $ 5,670 $ 10,154 $ 2,020
Proved 28,480 29,393 32,810
Exploration 49,337 33,192 17,927
Development 80,336 31,446 63,936
----------- ---------- ----------
Total costs incurred $ 163,823 $ 104,185 $ 116,693
=========== ========== ==========
</TABLE>
- ------------------------------
*These amounts represent costs incurred by the Company and excluded from the
amortization base until proved reserves are established or impairment is
determined.
38
<PAGE> 41
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
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, 1996 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.
39
<PAGE> 42
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 is as follows (in thousands):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows . . . . . . . . . . . . . . . . . . . . $ 1,312,815 $ 642,019 $ 400,766
Less related future:
Production costs . . . . . . . . . . . . . . . . . . . . (113,937) (84,999) (66,221)
Development and abandonment costs . . . . . . . . . . . . (107,205) (83,262) (45,704)
----------- ----------- ----------
Future net cash flows before income taxes . . . . . . . . . 1,091,673 473,758 288,841
10% annual discount for estimating timing of cash flows . . (231,856) (108,879) (58,247)
----------- ----------- ----------
Standardized measure of discounted future net cash
flows before income taxes . . . . . . . . . . . . . . . . 859,817 364,879 230,594
Future income tax expense, net of 10% annual discount . . . (247,889) (88,553) (50,592)
----------- ----------- ----------
Standardized measure of discounted future net cash flows . $ 611,928 $ 276,326 $ 180,002
=========== =========== ==========
</TABLE>
A summary of the changes in the standardized measure of discounted
future net cash flows applicable to proved oil and gas reserves is as follows
(in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Beginning of the period . . . . . . . . . . . . . . . . . . $ 276,326 $ 180,002 $ 116,129
---------- ---------- ----------
Revisions of previous estimates:
Changes in prices and costs . . . . . . . . . . . . . . 254,227 61,917 (22,877)
Changes in quantities . . . . . . . . . . . . . . . . . 9,554 691 (3,438)
Changes in future development costs . . . . . . . . . . --- 1,026 2,097
Development costs incurred during the period . . . . . . . 24,895 2,839 20,313
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs . . 229,314 87,760 85,089
Purchases of reserves in place . . . . . . . . . . . . . . 55,910 45,324 27,843
Accretion of discount . . . . . . . . . . . . . . . . . . . 36,488 23,059 15,916
Sales of oil and gas, net of production costs . . . . . . . (132,310) (80,371) (60,173)
Net change in income taxes . . . . . . . . . . . . . . . . (159,336) (37,961) (7,566)
Production timing and other . . . . . . . . . . . . . . . . 16,870 (7,960) 6,669
----------- ---------- ----------
Net increase . . . . . . . . . . . . . . . . . . . . . . . 335,602 96,324 63,873
----------- ---------- ----------
End of the period . . . . . . . . . . . . . . . . . . . . . $ 611,928 $ 276,326 $ 180,002
=========== ========== ==========
</TABLE>
40
<PAGE> 43
CORPORATE INFORMATION
<TABLE>
<CAPTION>
DIRECTORS OFFICERS ANNUAL MEETING
<S> <C> <C>
The Annual Meeting of Stockholders
CHARLES W. DUNCAN, JR. (*)(**)(70) JOE B. FOSTER (62) of Newfield Exploration Company
Private Investor Chairman, President and will be held May 1, 1997, 11:00 a.m.
Chief Executive Officer at the Wyndham Greenspoint Hotel,
JOE B. FOSTER (62) 12400 Greenspoint Drive,
Chairman, President and ROBERT W. WALDRUP (52) Houston, Texas.
Chief Executive Officer Vice President - Operations
Newfield Exploration Company
TERRY W. RATHERT (44) TRANSFER AGENT
JEFFREY A. HARRIS (*)(41) Vice President, Chief Financial Officer For information regarding change of
Managing Director and Secretary address or other matters concerning your
E.M. Warburg, Pincus & Co., L.L.C. stockholder account, please contact the
DAVID F. SCHAIBLE (37) transfer agent directly at:
HOWARD H. NEWMAN (*)(49) Vice President - Acquisitions &
Managing Director Development ChaseMellon Shareholders Services L.L.C.
E.M. Warburg, Pincus & Co., L.L.C. Overpeck Centre
WILLIAM D. SCHNEIDER (45) 85 Challenger Road
THOMAS G. RICKS (*)(**)(43) Manager - Exploration Ridgefield Park, NJ 07660
President and Chief Executive Officer (800) 635-9270
The University of Texas RONALD P. LEGE (52)
Investment Management Company Controller and Assistant Secretary
OUTSIDE LEGAL COUNSEL
C. E. (CHUCK) SHULTZ (*)(**)(57) C. WILLIAM AUSTIN (44) Vinson & Elkins L.L.P.
Chairman and Chief Executive Officer Legal Counsel and Assistant Secretary
Dauntless Energy Inc.
JAMES P. ULM, II (34) AUDITORS
DALE E. ZAND (*)(**)(70) Treasurer Coopers & Lybrand L.L.P.
Professor of Management Houston, Texas
Stern Graduate School of Business, MARKET INFORMATION
New York University The Company's common stock is traded
on the NYSE under the symbol NFX. CORPORATE ADDRESS
ROBERT W. WALDRUP (52) The stock began trading November 12, 363 North Sam Houston Parkway East,
Vice President - Operations 1993. The range of high and low Suite 2020
Newfield Exploration Company quarterly sales prices for 1995 and 1996, Houston, TX 77060
as reported by the NYSE, are set forth (281) 847-6000
(*) Member of the Compensation below:
Committee
(**)Member of the Audit FORM 10-K
Committee Stockholders may obtain without charge
HIGH LOW a copy of Newfield's Form 10-K report
---- --- as filed with the Securities and Exchange
Commission. For copies or answers to
1995 questions about Newfield Exploration
First Quarter 11 7/16 9 Company, you are invited to contact
Second Quarter 14 1/4 10 3/4 Stockholder Relations at the corporate
Third Quarter 16 1/16 12 3/8 address.
Fourth Quarter 15 1/4 13 5/16
1996
First Quarter 15 1/4 12 1/2
Second Quarter 20 15 1/8
Third Quarter 22 3/4 18 1/16
Fourth Quarter 26 1/2 22 5/16
On December 31, 1996, the closing sale
price for the Company's common stock was
$26 per share, after giving effect to the
2-for-1 common stock split.
Management believes after inquiry, that
the number of beneficial owners of the
Company's common stock is in excess of 2,000.
</TABLE>
<PAGE> 44
[NEWFIELD LOGO]
NEWFIELD EXPLORATION COMPANY
363 North Sam Houston Parkway East,
Suite 2020
Houston, Texas 77060
Tel: (281) 847-6000
Fax: (281) 847-6006
http://www.newfld.com
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference into the Registration
Statements on Form S-8 (Registration Nos. 33-72848, 33-79826 and 33-92182) of
Newfield Exploration Company (the "Company") of our report dated February 11,
1997 on our audits of the financial statements of the Company as of December 31,
1996 and 1995 and for each of the three years in the period ended December 31,
1996, which report is incorporated by reference in the Company's Annual Report
on Form 10-K for the year ended December 31, 1996.
/s/ COOPERS & LYBRAND L.L.P.
Coopers & Lybrand L.L.P.
Houston, Texas
March 5, 1997
<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, 1996 (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 and No. 33-92182).
/s/ RYDER SCOTT COMPANY
Ryder Scott Company
Petroleum Engineers
March 4, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NEWFIELD
EXPLORATION COMPANY'S BALANCE SHEET AT DECEMBER 31, 1996 AND STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1996, THAT ARE CONTAINED IN ITS FORM 10-K FOR
THE YEAR ENDED DECEMBER 31, 1996. 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-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 13,290
<SECURITIES> 0
<RECEIVABLES> 46,814
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 61,283
<PP&E> 529,176
<DEPRECIATION> 199,161
<TOTAL-ASSETS> 395,938
<CURRENT-LIABILITIES> 49,847
<BONDS> 60,000
0
0
<COMMON> 147,643
<OTHER-SE> 92,259
<TOTAL-LIABILITY-AND-EQUITY> 395,938
<SALES> 149,256
<TOTAL-REVENUES> 149,256
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 80,972
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 420
<INCOME-PRETAX> 59,286
<INCOME-TAX> 20,792
<INCOME-CONTINUING> 38,494
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 38,494
<EPS-PRIMARY> 1.03
<EPS-DILUTED> 0
</TABLE>
