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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, 2000
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)
DELAWARE 72-1133047
(State of incorporation) (I.R.S. Employer Identification No.)
363 NORTH SAM HOUSTON PARKWAY,
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:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
Common Stock, Par Value $0.01 per Share New York Stock Exchange
Rights to Purchase Series A Junior New York Stock Exchange
Participating Preferred Stock, Par Value
$0.01 per Share
6 1/2% Cumulative Quarterly Income Convertible New York Stock Exchange
Preferred Securities,
Series A, of Newfield Financial Trust I
(and the guarantee of the registrant
with respect thereto)
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $1,125,600,000 as of March 15, 2001 (based on
the last sale price of such stock as quoted on the New York Stock Exchange).
As of March 16, 2001 there were 44,682,181 shares of the registrant's
common stock, par value $0.01 per share, outstanding.
Documents incorporated by reference: Proxy Statement of Newfield
Exploration Company for the Annual Meeting of Stockholders to be held May 3,
2001, which is incorporated into Part III of this Form 10-K.
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TABLE OF CONTENTS
PAGE
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PART I
ITEM 1. BUSINESS.................................................... 1
Strategy.................................................... 1
Marketing................................................... 3
Competition................................................. 3
Employees................................................... 3
Regulation and Other Factors Affecting Our Business......... 4
ITEM 2. PROPERTIES.................................................. 4
Gulf of Mexico.............................................. 4
U.S. Onshore Gulf Coast..................................... 4
Anadarko Basin.............................................. 4
International............................................... 4
Proved Reserves and Future Net Cash Flows................... 5
Finding Costs............................................... 6
Development, Exploration and Acquisition Capital
Expenditures.............................................. 6
Drilling Activity........................................... 7
Productive Wells............................................ 7
Acreage Data................................................ 8
Title to Properties......................................... 8
ITEM 3. LEGAL PROCEEDINGS........................................... 8
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 8
ITEM 4A. EXECUTIVE OFFICERS.......................................... 9
PART II
ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS..... 10
ITEM 6. SELECTED FINANCIAL DATA..................................... 11
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................. 13
Accounting Policies......................................... 13
Results of Operations....................................... 14
Liquidity and Capital Resources............................. 18
Hedging..................................................... 19
Regulation.................................................. 23
Other Factors Affecting Our Business........................ 26
Forward Looking Information................................. 30
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK...................................................... 33
Oil and Gas Prices.......................................... 33
Interest Rates.............................................. 33
Foreign Currency Exchange Rates............................. 33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 34
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.................................. 70
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PAGE
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 70
ITEM 11. EXECUTIVE COMPENSATION...................................... 70
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT................................................ 70
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 70
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K....................................................... 70
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All references in this report to "Newfield," "we," "us" or "our" are to
Newfield Exploration Company and its subsidiaries. Unless otherwise noted, all
information in this report relating to oil and gas reserves and the estimated
future net cash flows attributable to those reserves are based on estimates we
prepared and are net to our interest. If you are not familiar with the oil and
gas terms used in this report, please refer to the explanations of such terms
under the caption "Commonly Used Oil and Gas Terms" at the end of Item 7 of this
report.
PART I
ITEM 1. BUSINESS
Newfield is an independent oil and gas company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. At year-end
2000, we had proved reserves of 687 Bcfe comprised of 520 Bcf of natural gas and
28 MMBbls of oil and condensate. Natural gas accounted for 76% of those proved
reserves. Approximately 82% of our reserves at December 31, 2000 were proved
developed and 95% were located in the U.S.
Newfield was founded in 1989 and acquired its first oil and gas reserves in
1990. Since that time, we have grown rapidly. Our initial focus area was the
Gulf of Mexico. Over the last several years we have expanded our areas of
operation to include the U.S. onshore Gulf Coast, offshore northwest Australia,
Bohai Bay, offshore China, and, through the recent acquisition of Lariat
Petroleum, the Anadarko Basin of Oklahoma. While approximately 40% of our proved
reserves are now located onshore in the U.S., our largest focus area remains the
Gulf of Mexico, which accounts for approximately 58% of our proved reserves.
STRATEGY
Our growth strategy has remained unchanged and is based on the following
elements:
-- growing our reserves through the drilling of a balanced portfolio;
-- balancing exploration with the acquisition and exploitation of proved
properties;
-- focusing on select geographic areas;
-- controlling operations and costs;
-- using 3-D seismic data and other advanced technologies; and
-- attracting and retaining a quality workforce through equity ownership
and other performance-based incentives.
DRILLING PROGRAM. We have an active, technology-driven drilling program
conducted by five multi-disciplined teams. We balance our drilling program
between a smaller number of higher risk, higher potential prospects and a
greater number of lower risk, low and moderate potential prospects. We
continuously evaluate opportunities and have a substantial inventory of
prospects, including nearly 200 exploration/exploitation and development wells
that we expect to drill in the U.S. in 2001. This compares to 55 wells drilled
in 2000. We expect to drill about 175 wells onshore during 2001, including about
150 in the Anadarko Basin. In addition, we also expect to drill up to five wells
in the Bohai Bay, offshore China, and up to four exploration wells offshore
Australia. Our 41 well domestic exploration/exploitation drilling program
resulted in 31 successful wells during 2000. Internationally, we drilled two
successful wells and four dry holes in 2000.
BALANCE. Since inception, we have added 44% of our proved reserves through
acquisitions, 33% through exploration and 23% by exploitation and development of
acquired properties. Our exploration, acquisition and exploitation and
development activities are complimentary and often overlap. Proved properties we
acquire typically have exploration or exploitation potential. Acquisitions can
be used to establish us in a new, or increase our presence in an existing, focus
area. Acquisitions may also help create
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infrastructure that will facilitate our capture of other opportunities on a more
attractive basis. In our exploration efforts, we use information gathered while
evaluating production on acquisition candidates and adjacent acreage as
appropriate. In addition, a successful exploratory prospect may reveal similar
untested reserve potential on an adjacent property, making its purchase
attractive.
Exploration. We acquire exploration prospects through proved property
acquisitions, farm-ins from other operators and federal and state lease sales.
During 2000, we invested $100.2 million in exploration activities. The largest
component of that expenditure was in the Gulf of Mexico.
Acquisitions. We actively pursue the acquisition of proved oil and gas
properties in our focus areas. We use the same team approach used in our
drilling activities to evaluate acquisition opportunities. Our extensive
seismic, land and production databases, along with regional geological
interpretations, supplement the information provided by potential sellers. In
the first quarter of 2000, we invested $139 million to acquire three producing
gas fields in South Texas. On January 23, 2001, we acquired Lariat Petroleum in
a transaction valued at approximately $333 million. Lariat's operations are
focused in the Anadarko Basin of Oklahoma.
Development. Our spending on development projects in 2000 was $139.0
million, including exploitation and development drilling and well recompletions.
During 2000, four major Gulf of Mexico development projects were completed on
discoveries made during 1999.
GEOGRAPHIC FOCUS. One of our founding and continuing business principles
is focus. We believe that long-term success requires extensive knowledge of
geologic and operating conditions in the areas where we operate. Because of this
belief, we focus our efforts on a limited number of geographic areas where we
can use our core competencies, such as geological and geophysical analyses
through the application of 3-D seismic data and other advanced technologies,
expertise in marine operations and significant influence on operations. We also
believe that geographic focus allows us to make the most efficient use of our
capital and personnel because we can manage a large asset base with a relatively
small number of employees and add successful wells and proved property
acquisitions at relatively low incremental costs.
Gulf of Mexico. Our management and technical personnel have extensive
experience in our largest focus area. The Gulf of Mexico is a prolific oil and
gas province, accounting for approximately 25% of domestic natural gas
production. It has substantial existing infrastructure, including gathering
systems, platforms and pipelines, and numerous drilling and service companies
maintain a significant presence there, facilitating cost effective operations
and timely development of discoveries. We believe that the Gulf of Mexico has
significant remaining undiscovered reserve potential.
Onshore Gulf Coast. As a natural extension of our offshore efforts, we
established onshore Gulf Coast operations in 1995. As of February 28, 2001, we
held an interest in more than 44,000 gross acres in the coastal areas of Texas
and Louisiana. With similar geologic features, our onshore program benefits from
our core competencies. Over the last three years, we have hired more than 20
experienced professionals to explore and develop our growing onshore Gulf Coast
operations.
Anadarko Basin. In January 2001, we added the Anadarko Basin as a focus
area by acquiring Lariat Petroleum. Lariat is a significant operator, with more
than 1,350 wells and 256 Bcfe of proved reserves located primarily in the
Anadarko Basin of Oklahoma. By acquiring a going concern, we added a team of
professionals with extensive experience in the area and a proven track record of
profitably growing production and reserves. We believe that our entry into the
Anadarko Basin provides an opportunity for future growth. It is a gas-rich
province characterized by multiple productive zones, relatively low drilling
costs and long life reserves. Like the Gulf of Mexico, it is a mature basin,
offering the potential to consolidate properties.
International. In the mid-1990s we began to consider opportunities in
select international areas where we could use our core competencies under an
attractive fiscal regime. In 1997, we acquired a 35% interest in a production
sharing license that now covers approximately 300,000 acres in the Bohai Bay,
offshore China. In mid-1999, we acquired interests in two producing oil fields,
Jabiru and Challis, and ten exploration and production licenses covering 3.0
million gross acres in the Timor Sea, offshore Australia. We continue to
evaluate and pursue opportunities for international expansion in Australia,
China and South America.
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CONTROL OF OPERATIONS AND COSTS. We prefer to operate our properties. By
controlling operations, we can better manage production performance, control
operating expenses and capital expenditures, consider the application of
technologies and influence timing. At the end of 2000, we operated 82% of our
total equivalent production. In an effort to control costs, we also use
independent contractors for much of our domestic offshore operating activities.
TECHNOLOGY. We use advanced technologies in our exploration and
development activities to help reduce risks and lower costs. At February 28,
2001, we held licenses or otherwise had access to 3-D seismic surveys covering
approximately 2,900 blocks (14.4 million acres) in the Gulf of Mexico, 1,700
square miles in southern Louisiana and Texas, 400 square miles in the Anadarko
Basin, 5,000 square kilometers offshore Australia, including coverage of the two
producing fields we operate, and 350 square kilometers covering the area where
we are currently drilling offshore China.
EQUITY OWNERSHIP AND INCENTIVE COMPENSATION. Another of our founding and
continuing business principles is both to reward and provide incentives to our
employees through equity ownership and performance-based compensation. As of
February 28, 2001, our employees owned or had options to acquire an aggregate of
approximately 9% of our outstanding common stock on a fully diluted basis. Due
to our 2000 financial success, performance-based pay accounted for more than 50%
of our total compensation expense in 2000.
MARKETING
We market nearly all of the crude oil, hydrocarbon condensate and natural
gas production from properties we operate for both our account and the account
of the other working interest owners in these properties. Substantially all of
our natural gas production is sold to a variety of purchasers under short-term
(less than 12 months) contracts or 30-day spot gas purchase contracts. Oil sales
contracts are short-term and are based upon posted prices plus negotiated
bonuses. For a list of purchasers of our oil and gas production that accounted
for 10% or more of consolidated revenue for the three preceding calendar years,
please see "Major Customers" in Note 1 to our consolidated financial statements.
Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not have a material adverse
effect on us.
COMPETITION
Competition in the oil and gas industry is intense, particularly with
respect to the acquisition of producing properties and proved undeveloped
acreage. For a further discussion of this competitive environment, please see
the information set forth under the caption "Additional Factors Affecting Our
Business" in Item 7 of this report.
EMPLOYEES
At February 28, 2001, we had 348 employees. The significant increase over
our 1999 year-end employee count reflects our acquisition of Lariat Petroleum in
January 2001. We believe that our relationships with our employees are
satisfactory.
Our 224 U.S. employees are primarily professionals, including geologists,
geophysicists and engineers. None of our U.S. employees are covered by a
collective bargaining agreement. From time to time, we utilize 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. U.S. offshore field and
on-site production operation services, such as pumping, maintenance,
dispatching, inspection and testing, are generally provided by independent
contractors.
We have 124 employees located in Australia. Our Perth, Australia office
employs 26 people to manage our offshore operations. We also employ 98 offshore
workers. The employment of the offshore employees is covered by collective
bargaining agreements. At December 31, 2000, there were no significant issues
outstanding under those agreements.
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REGULATION AND OTHER FACTORS AFFECTING OUR BUSINESS
For a discussion of the significant governmental regulations to which our
business is subject and other significant factors that may affect our business,
please see the information set forth under the captions "Regulation" and
"Additional Factors Affecting Our Business" in Item 7 of this report.
ITEM 2. PROPERTIES
Our ten largest properties accounted for approximately 40% of our
equivalent proved reserves at year-end 2000. No single property held more than
11% of our equivalent proved reserves as of such date, nor did any single
property hold more than 10% of the net present value of proved reserves as of
such date.
GULF OF MEXICO
The majority of our proved reserves are located in federal waters offshore
Texas and Louisiana. These properties are in water depths ranging from 45 to
more than 800 feet. For 2000, no single field accounted for more than 10% of our
equivalent production. As of December 31, 2000, we owned interests in 168 leases
(708,549 gross acres) and operated 131 platforms. During 2000, we drilled or
participated in 36 wells in the Gulf of Mexico, 30 of which were successful. We
also completed four major development projects associated with discoveries made
during 1999.
U.S. ONSHORE GULF COAST
We currently own an interest in more than 60,000 gross acres in the U.S.
onshore regions of South Texas and southern Louisiana and expect to continue
expanding our operations in these areas. In early 2000, we acquired three
producing gas fields in South Texas for $139 million. During 2000, we drilled or
participated in 15 wells onshore, of which 13 were successful. Our net
production from the Gulf Coast region was approximately 70 MMcfe/d as of
February 2001.
ANADARKO BASIN
Our acquisition of Lariat Petroleum in January 2001 gave us a significant
presence in the Anadarko Basin of Oklahoma. As a result of this transaction, we
acquired 256 Bcfe of proved reserves (230 Bcfe in the Anadarko Basin) and
interests in more than 1,350 wells (570 wells in the Anadarko Basin), 1,355,000
gross (210,000 net) acres (1,240,000 gross (202,000 net) in the Anadarko Basin)
and 102,000 gross (15,000 net) mineral acres (all in the Anadarko Basin). We
operate in excess of 500 of the wells located in the Anadarko Basin and 76% of
total proved reserves. At December 31, 2000, Lariat was producing approximately
60 MMcfe/d, 75% of which was natural gas.
INTERNATIONAL
AUSTRALIA. We own a 50% interest in two producing oil fields offshore
Australia and two related floating production, storage and off-loading vessels.
In addition, we have exploration permits on about 2.5 million gross acres. Our
production during 2000 averaged 4,572 BOPD and benefited from our gas lift
optimization program. This program helped increase both production and ultimate
oil recovery from the Jabiru and Challis Fields and we took a reserve addition
of about 1 MMBbls during the year. Our drilling results to date in Australia
have been disappointing. During 2000, we drilled four unsuccessful wells -- two
in-fill wells and two wildcat wells. In early 2001, we drilled a dry hole on our
third exploration prospect. We have four additional exploration commitment wells
that we anticipate will be drilled in late 2001.
CHINA. We own a 35% interest in Block 05/36 in the Bohai Bay, offshore
China. Our interest is subject to a 51% back in by the Chinese government. The
block covers 300,000 acres and is operated by Kerr-McGee. There currently is no
production on the block. We made our first international discovery during
2000 -- the CFD 12-1 Field tested at more than 2,562 BOPD of relatively light
oil. In late 2000, a 350 square kilometer 3-D seismic survey over Block 05/36
was completed. The data from the survey are being used to determine locations
for up to five appraisal wells planned for 2000. Our second appraisal well
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was drilling at the time this report was filed with the SEC. The results of the
appraisal wells will help determine commerciality of the CFD 12-1 Field. We also
plan to drill one wildcat well on Block 05/36 in 2001.
PROVED RESERVES AND FUTURE NET CASH FLOWS
The following table shows our estimated net proved oil and gas reserves,
the standardized measure of future after-tax net cash flows before 10% annual
discount and the present value of estimated future after-tax net cash flows
related to such reserves as of December 31, 2000. The present value of estimated
future pre-tax and after-tax net cash flows was prepared using year-end oil and
gas prices, discounted at 10% per year.
PROVED RESERVES
------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ----------
UNITED STATES:
Oil and condensate (MBbls)......................... 18,657 3,894 22,551
Gas (MMcf)......................................... 416,368 103,355 519,723
Total proved reserves (MMcfe)...................... 528,310 126,719 655,029
Standardized measure of estimated future after-tax
net cash flows before 10% annual discount (in
thousands)....................................... $3,473,609
Present value of estimated future after-tax net
cash flows (in thousands)........................ $2,653,353
AUSTRALIA:
Oil and condensate (MBbls)......................... 5,383 -- 5,383
Gas (MMcf)......................................... -- -- --
Total proved reserves (MMcfe)...................... 32,298 -- 32,298
Standardized measure of estimated future after-tax
net cash flows before 10% annual discount (in
thousands)....................................... $ 20,682
Present value of estimated future after-tax net
cash flows (in thousands)........................ $ 16,905
TOTAL:
Oil and condensate (MBbls)......................... 24,040 3,894 27,934
Gas (MMcf)......................................... 416,368 103,355 519,723
Total proved reserves (MMcfe)...................... 560,608 126,719 687,327
Standardized measure of estimated future after-tax
net cash flows before 10% annual discount (in
thousands)....................................... $3,494,291
Present value of estimated future after-tax net
cash flows (in thousands)........................ $2,670,258
As mandated by the SEC, future after-tax net cash flows attributable to our
natural gas reserves were estimated by using a year-end 2000 base price of $9.52
per Mcf. On March 16, 2001, that base price was $4.92 per Mcf. If our future
after-tax net cash flows were estimated as of such date, such cash flows would
be significantly lower than at December 31, 2000.
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. For a discussion of these uncertainties, see
"Additional Factors Affecting Our Business" and "Forward Looking Statements"
under Item 7 of this report.
As an operator of domestic oil and gas properties, we have 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 above. 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).
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FINDING COSTS
The following table sets forth certain information regarding the costs
associated with finding, acquiring and developing our proved oil and gas
reserves:
CAPITALIZED RESERVES COST TO
COSTS(1) ADDED FIND AND DEVELOP(2)
-------------- -------- -------------------
(IN THOUSANDS) (MMCFE) (PER MCFE)
1996........................................ $ 162,315 119,050 $1.36
1997........................................ 237,574 190,279 1.25
1998........................................ 304,891 166,475 1.83
1999........................................ 206,157 194,970 1.06
2000........................................ 367,526 232,219 1.58
---------- ------- -----
Five-year period ended December 31, 2000.... $1,278,463 902,993 $1.42
========== ======= =====
---------------
(1) Capitalized costs represent our capitalized expenditures as shown in the
immediately following table except that acquisition and exploration costs
relating to foreign locations other than Australia and interest capitalized
are not included.
(2) The cost to find and develop per Mcfe for 2000 and the five-year period
ended December 31, 2000 would have been $1.63 and $1.46, respectively, if we
had included all capitalized expenditures as shown in the immediately
following table.
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the
capitalized costs we incurred in the purchase of proved and unproved properties
and in our development and exploration activities:
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(IN THOUSANDS)
Property acquisition:
Unproved
properties -- U.S. ........ $ 23,621 $ 5,849 $ 3,400 $ 31,541 $ 5,670
Unproved properties -- Other
International.............. 528 -- -- 7,196 --
Proved properties -- U.S. .... 115,567 77,673 86,219 30,368 28,480
Proved
properties -- Australia.... (295) 2,490 -- -- --
Exploration -- U.S. ............ 88,572 44,332 60,087 59,787 48,525
Exploration -- Australia........ 10,448 3,852 -- -- --
Exploration -- Other
International................. 5,286 1,266 1,512 4,908 --
Development -- U.S. ............ 125,823 70,913 155,185 115,878 79,640
Development -- Australia........ 3,760 1,048 -- -- --
Interest capitalized -- U.S. ... 5,323 2,376 4,369 3,481 1,508
-------- -------- -------- -------- --------
Total capitalized
costs............... $378,663 $209,799 $310,772 $253,159 $163,823
======== ======== ======== ======== ========
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DRILLING ACTIVITY
The following table sets forth our drilling activity for each year of the
three-year period ended December 31, 2000:
2000 1999 1998
------------ ----------- ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- --- ----- ----
Exploratory wells:
Productive -- U.S. ......................... 19 10.9 6 3.9 8 4.4
Nonproductive -- U.S. ...................... 5 2.4 6 3.1 8 5.8
Nonproductive -- Australia.................. 2 1.1 -- -- -- --
Productive -- China......................... 2 0.8 -- -- -- --
Nonproductive -- China...................... -- -- -- -- -- --
-- ---- -- --- -- ----
Total............................... 26 14.4 12 7.0 16 10.2
== ==== == === == ====
Development wells:
Productive -- U.S. ......................... 24 15.0 7 4.8 17 11.4
Nonproductive -- U.S. ...................... 3 2.0 1 0.6 2 0.9
Nonproductive -- Australia.................. 2 1.0 -- -- -- --
-- ---- -- --- -- ----
Total............................... 29 18.0 8 5.4 19 12.3
== ==== == === == ====
We were in the process of drilling 4 gross (2.3 net) exploratory wells and
4 gross (3.5 net) developmental wells at December 31, 2000.
PRODUCTIVE WELLS
The following table sets forth the number of platforms we operate and the
number of productive oil and gas wells in which we owned an interest as of
December 31, 2000:
COMPANY OUTSIDE TOTAL
OPERATED OPERATED PRODUCTIVE
COMPANY WELLS WELLS WELLS
OPERATED ------------- ------------ -------------
PLATFORMS GROSS NET GROSS NET GROSS NET
--------- ----- ----- ----- ---- ----- -----
Offshore Louisiana
Federal:
Oil......................... 20 57 37.7 10 2.0 67 39.7
Gas......................... 94 117 79.0 56 10.2 173 89.2
State:
Gas......................... 2 1 1.0 -- -- 1 1.0
Onshore Louisiana
Gas............................ -- 4 3.3 10 2.3 14 5.6
Offshore Texas
Federal:
Oil......................... 2 16 9.6 -- -- 16 9.6
Gas......................... 13 23 13.7 7 2.7 30 16.4
Onshore Texas
Gas............................ -- 21 18.3 -- -- 21 18.3
Offshore Australia
Oil............................ -- 12 6.0 -- -- 12 6.0
--- --- ----- -- ---- --- -----
Total.................. 131 251 168.6 83 17.2 334 185.8
=== === ===== == ==== === =====
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ACREAGE DATA
The following table shows certain information regarding our developed and
undeveloped lease acreage as of December 31, 2000:
DEVELOPED ACRES UNDEVELOPED ACRES
------------------- ---------------------
GROSS NET GROSS NET
--------- ------- --------- ---------
Offshore Louisiana:
Federal waters.......................... 493,801 271,848 65,280 43,053
State waters............................ 2,512 1,667 2,426 1,415
Onshore Louisiana......................... 10,482 9,675 4,105 2,457
Offshore Texas:
Federal waters.......................... 89,983 45,881 54,547 39,767
Onshore Texas............................. 14,076 10,702 15,831 10,776
Offshore Australia........................ 431,437 217,851 2,068,474 882,387
Offshore China............................ -- -- 312,910 109,519
--------- ------- --------- ---------
Total........................... 1,042,291 557,624 2,523,573 1,089,374
========= ======= ========= =========
Leases covering approximately 19,182 (5,629 net), 106,595 (50,792 net),
1,150,550 (375,978 net), 1,189,146 (625,087 net) and 15,760 (15,760 net)
undeveloped acres are scheduled to expire in 2001, 2002, 2003, 2004 and 2005,
respectively.
TITLE TO PROPERTIES
We believe that we have satisfactory title to all of our producing
properties in accordance with generally accepted industry standards. Our
properties are subject to customary royalty interests, liens incident to
operating agreements, liens for current taxes and other burdens that we believe
do not materially interfere with the use of or affect the value of such
properties. The MMS must approve all transfers of record title of or operating
rights on leases located in federal waters of the Gulf of Mexico. The MMS
approval process can in some cases delay the requested transfer for a
significant period of time.
ITEM 3. LEGAL PROCEEDINGS
We have 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, we do not expect these matters to have a material
adverse effect on our financial position, cash flows or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of 2000.
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ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth the names and ages (as of February 28, 2001)
of and positions held by our executive officers. Our executive officers serve at
the discretion of the Board of Directors.
NAME AGE POSITION
---- --- --------
David A. Trice........................ 52 President and Chief Executive Officer
and a Director
Robert W. Waldrup..................... 55 Vice President - Operations and a
Director
Randy A. Foutch....................... 49 Vice President - Mid-Continent and
President and Chief Executive
Officer of Newfield Exploration
Mid-Continent Inc.
Terry W. Rathert...................... 47 Vice President, Chief Financial
Officer and Secretary
David F. Schaible..................... 39 Vice President - Acquisitions and
Development
Elliott Pew........................... 45 Vice President - Exploration
William D. Schneider.................. 48 Vice President - International
C. William Austin..................... 47 Legal Counsel and Assistant Secretary
Ronald P. Lege........................ 55 Controller and Assistant Secretary
Susan G. Riggs........................ 42 Treasurer
Each of the executive officers has held the above positions for the past
five years, with the exception of the following:
DAVID A. TRICE was one of our founders. From 1991 to 1997 he served as
President and Chief Executive Officer and a Director of Huffco Group, Inc. He
rejoined Newfield in May 1997 as Vice President - Finance and International. He
was appointed President and Chief Operating Officer in May 1999 and to his
present position on February 1, 2000. He has served as a director since February
2000.
RANDY A. FOUTCH founded Lariat Petroleum, Inc. in April 1996 and served as
its Chairman of the Board, President and Chief Executive Officer. Following our
acquisition of Lariat in January 2001, Mr. Foutch continued as President and
Chief Executive Officer of Lariat's successor, Newfield Exploration
Mid-Continent Inc. Mr. Foutch was elected to his position with Newfield at the
time of our acquisition of Lariat.
ELLIOTT PEW has served as Vice President - Exploration since January 1998.
Prior to joining us, he served as Senior Vice President of Louis Dreyfus Natural
Gas Company's Gulf Coast Region and, prior to Louis Dreyfus' merger with
American Exploration Company in October 1997, as Senior Vice President of
Exploration for American Exploration Company from March 1997 to the date of such
merger. From 1992 to March 1997 Mr. Pew was Vice President of Exploration for
American Exploration Company.
WILLIAM D. SCHNEIDER, one of our founders, has served us as a Vice
President since January 1998. From 1992 to January 1998 he served as
Manager-Exploration.
SUSAN G. RIGGS was named to her present position in August 1999. From May
1997 to August 1999, she served us as a Financial Analyst. Mrs. Riggs was
Treasurer/Controller for the Huffco Group from 1995 to May 1997.
9
13
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is listed on the New York Stock Exchange under the symbol
"NFX." The following table sets forth, for the periods indicated, the range of
the high and low sales prices of our common stock as reported by the New York
Stock Exchange. Our common stock began trading in decimals on January 29, 2001.
Prior thereto, sales prices were reported as fractions. We have converted all
sales reported in fractions to decimals and have rounded such decimal prices to
the nearest $0.01.
HIGH LOW
----- -----
1999
First Quarter............................................. 24.75 14.88
Second Quarter............................................ 28.50 22.12
Third Quarter............................................. 35.00 27.44
Fourth Quarter............................................ 32.94 21.00
2000
First Quarter............................................. 38.31 24.50
Second Quarter............................................ 45.38 32.88
Third Quarter............................................. 50.25 31.81
Fourth Quarter............................................ 49.50 36.25
2001
First Quarter (through February 28, 2001)................. 47.75 32.50
On March 16, 2001 the last reported sale price of our common stock on the
New York Stock Exchange Composite Tape was $36.05 per share.
As of March 16, 2001 there were approximately 266 holders of record of our
common stock.
We have not paid any cash dividends in the past on our common stock and do
not intend to pay cash dividends in the foreseeable future. We intend to retain
earnings for the future operation and development of our business. Any future
cash dividends to holders of common stock would depend on future earnings,
capital requirements, our financial condition and other factors determined by
our Board of Directors. The covenants contained in our credit facility could
restrict our ability to pay cash dividends.
On May 4, 2000, we issued 5,250 restricted shares of our common stock in
transactions not involving any public offering that were exempt from the
provisions of Section 5 of the Securities Act pursuant to Section 4(2) of the
such act. The shares were granted to our non-employee directors (other than one
non-employee director who elected not to receive a grant) pursuant to the
Newfield Exploration Company 2000 Non-Employee Director Restricted Stock Plan.
Only non-employee directors are eligible to receive grants pursuant to the plan
and such grants are automatic unless a non-employee director elects in advance
to not receive a grant and are based on a formula set forth in the plan.
10
14
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FIVE-YEAR FINANCIAL AND RESERVE DATA
The following table shows selected consolidated financial data derived from
our consolidated financial statements and reserve data derived from our
supplementary oil and gas disclosures set forth in Item 8 of this report. The
data should be read in conjunction with the information under the caption
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Item 7 of this report.
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
---------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
INCOME STATEMENT DATA:
Oil and gas revenues(1)............ $ 526,642 $ 287,889 $ 199,474 $ 201,755 $ 150,812
---------- --------- --------- --------- ---------
Operating expenses:
Lease operating.................. 65,372 45,561 35,345 24,308 16,946
Production and other taxes....... 10,288 2,215 -- -- --
Transportation(1)................ 5,984 5,922 3,789 2,356 1,556
Depreciation, depletion and
amortization.................. 191,182 152,644 123,147 94,000 64,026
Ceiling test writedown........... 503 -- 104,955 4,254 --
General and administrative(2).... 32,084 16,404 12,070 12,270 9,495
---------- --------- --------- --------- ---------
Total operating
expenses............... 305,413 222,746 279,306 137,188 92,023
---------- --------- --------- --------- ---------
Income (loss) from operations...... 221,229 65,143 (79,832) 64,567 58,789
Interest income (expense), net..... (16,540) (13,128) (8,544) (2,146) 497
---------- --------- --------- --------- ---------
Income (loss) before income
taxes............................ 204,689 52,015 (88,376) 62,421 59,286
Income tax provision (benefit)..... 69,980 18,811 (30,677) 21,818 20,792
---------- --------- --------- --------- ---------
Income before cumulative effect of
change in accounting principle... $ 134,709 $ 33,204 $ (57,699) $ 40,603 $ 38,494
Cumulative effect of change in
accounting principle(3).......... (2,360) -- -- -- --
---------- --------- --------- --------- ---------
Net income......................... $ 132,349 $ 33,204 $ (57,699) $ 40,603 $ 38,494
========== ========= ========= ========= =========
Earnings per share:
Basic --
Income before cumulative effect
of change in accounting
principle..................... $ 3.18 $ 0.81 $ (1.55) $ 1.14 $ 1.10
Cumulative effect of change in
accounting principle(3)....... (0.05) -- -- -- --
---------- --------- --------- --------- ---------
Net income....................... $ 3.13 $ 0.81 $ (1.55) $ 1.14 $ 1.10
========== ========= ========= ========= =========
Diluted --
Income before cumulative effect
of change in accounting
principle..................... $ 2.98 $ 0.79 $ (1.55) $ 1.07 $ 1.03
Cumulative effect of change in
accounting principle(3)....... (0.05) -- -- -- --
---------- --------- --------- --------- ---------
Net income....................... $ 2.93 $ 0.79 $ (1.55) $ 1.07 $ 1.03
========== ========= ========= ========= =========
Weighted average number of shares
outstanding for basic earnings
per share........................ 42,333 41,194 37,312 35,612 34,872
Weighted average number of shares
outstanding for diluted earnings
per share........................ 47,228 42,294 37,312 38,017 37,409
11
15
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
---------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
CASH FLOW DATA:
Net cash provided by operating
activities before changes in
operating assets and
liabilities...................... $ 383,524 $ 205,553 $ 141,948 $ 161,852 $ 125,226
Net cash provided by operating
activities....................... 316,444 184,903 146,575 160,338 127,494
Net cash used in investing
activities....................... (355,547) (210,817) (318,991) (242,962) (159,537)
Net cash provided by financing
activities....................... 15,933 67,758 164,291 77,551 32,800
BALANCE SHEET DATA (AT END OF
PERIOD):
Working capital surplus
(deficit)........................ $ 38,089 $ 35,202 $ (8,806) $ 372 $ 11,436
Oil and gas properties, net........ 833,315 644,842 578,423 483,954 328,615
Total assets....................... 1,023,250 781,561 629,311 553,621 395,938
Long-term debt..................... 133,711 124,679 208,650 129,623 60,000
Convertible preferred securities... 143,750 143,750 -- -- --
Stockholders' equity............... 519,455 375,018 323,948 292,048 239,902
RESERVE DATA (AT END OF PERIOD):
Proved reserves:
Oil and condensate (MBbls)....... 27,934 25,770 15,171 16,307 13,659
Gas (MMcf)....................... 519,723 440,173 422,277 337,481 241,385
Total proved reserves (MMcfe).... 687,327 594,790 513,304 435,323 323,339
Standardized measure of estimated
future after-tax net cash flows
before 10% annual discount....... $3,494,291 $ 913,296 $ 559,264 $ 629,861 $ 776,938
Present value of future after-tax
net cash flows................... $2,670,258 $ 732,519 $ 451,156 $ 502,948 $ 611,928
---------------
(1) As a result of the adoption of Emerging Issues Task Force (EITF) No. 00-10,
"Accounting for Shipping and Handling Fees and Costs," we have reclassified
to operating expenses for all periods presented, third party costs incurred
to transport production to our sales point instead of as a reduction of the
related revenues as previously reported.
(2) General and administrative expense includes non-cash stock compensation
charges of $3,047, $1,999, $2,222, $1,177 and $1,943 for 2000, 1999, 1998,
1997 and 1996, respectively. See Note 8 to our consolidated financial
statements.
(3) We adopted SEC Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition
in Financial Statements" effective January 1, 2000. The adoption of SAB No.
101 requires us to report crude oil inventory associated with our Australian
offshore operations at lower of cost or market, which is a change from the
historical policy of recording such inventory at market value on the balance
sheet date, net of estimated costs to sell. The cumulative effect of the
change from the acquisition date of our Australian operations in July 1999
through December 31, 1999 is a reduction in net income of $2.36 million, or
$0.05 per diluted share, and is shown as the cumulative effect of change in
accounting principle on the consolidated statement of income for the year
ended December 31, 2000. The pro forma effect had SAB No. 101 been applied
retroactively in 1999 would have reduced net income by $2.36 million, or
$0.06 per diluted share. SAB No. 101 would not have effected periods prior
to the acquisition of the Company's Australian operations in July 1999.
12
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
ACCOUNTING POLICIES
We use the full cost method of accounting. Under this method, all costs
incurred in the acquisition, exploration and development of oil and gas
properties are capitalized into cost centers that are established on a
country-by-country basis. For each cost center, at the end of each quarter, the
net capitalized costs of oil and gas properties are limited to the lower of
unamortized cost 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 period-end oil and gas prices; plus the cost of properties not being
amortized, if any; plus the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any; less related income
tax effects. If net capitalized costs of oil and gas properties exceed the
ceiling limit, we are subject to a ceiling test writedown to the extent of such
excess. A ceiling test writedown is a non-cash charge to earnings. If required,
it would reduce earnings and impact stockholders' equity in the period of
occurrence and result in lower depreciation, depletion and amortization expense
in future periods.
The risk that we will be required to writedown the carrying value of our
oil and gas properties increases when oil and gas prices are depressed or if we
have substantial downward revisions in our estimated proved reserves.
Application of these rules during periods of relatively low oil or gas prices,
even if temporary, increases the probability of a ceiling test writedown. In
accordance with full cost accounting rules, the Company recorded a charge of
$0.5 million in 2000 related to abandoned prospect costs in foreign locations
other than Australia or China. Primarily because of low oil and gas prices, we
recorded a domestic ceiling test writedown at December 31, 1998 of $105.0
million. Because of the volatility of oil and gas prices, no assurance can be
given that we will not experience a ceiling test writedown in future periods.
See the discussion regarding fluctuations in oil and gas prices under the
caption "-- Other Factors Affecting Our Business" in this Item 7.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The FASB has subsequently issued
SFAS Nos. 137 and 138, which are amendments to SFAS No. 133. SFAS No. 133 is
effective for fiscal years beginning after June 30, 2000. We adopted SFAS No.
133 on January 1, 2001.
SFAS No. 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. All derivatives will be recorded on the
balance sheet at fair value and changes in the fair value of derivatives will be
recorded each period in current earnings or other comprehensive income,
depending on whether a derivative is designated as part of a hedge transaction
and, if it is, depending on the type of transaction. Our derivative contracts
consist primarily of cash flow hedge transactions in which we hedge the
variability of cash flows related to a forecasted transaction. Changes in the
fair value of these derivative instruments will be recorded in other
comprehensive income and will be reclassified as earnings in the periods in
which earnings are impacted by the variability of the cash flows of the hedged
item. The ineffective portion related to basis changes and time value of all
hedges will be recognized in current period earnings.
In accordance with the transition provisions of SFAS No. 133, on January 1,
2001, in connection with our hedging activities, we recorded as cumulative
effect adjustments a loss of $74.2 million (net of tax of $40.0 million) in
accumulated other comprehensive loss and a loss of $4.8 million (net of tax of
$2.6 million) in 2001 earnings. In addition, the adoption resulted in the
recognition of $17.7 million of derivative assets and $139.3 million of
derivative liabilities on the balance sheet on January 1, 2001. Based on fair
values at January 1, 2001 and the settlement dates of such derivatives, we
expect to reclassify approximately $75.3 million (net of tax of $40.5 million)
of the transition adjustment recorded in accumulated other comprehensive loss to
earnings in 2001.
We will not be in violation of any debt covenants or other contracts as a
result of implementing SFAS No. 133.
13
17
In the fourth quarter of 2000 we adopted SEC Staff Accounting Bulletin
(SAB) No. 101, "Revenue Recognition in Financial Statements." SAB No. 101
requires us to report crude oil inventory associated with our Australian
offshore operations at lower of cost or market, which is a change from our
historical policy of recording such inventory at market value on the balance
sheet date, net of estimated costs to sell. The cumulative effect of the change
from the acquisition date of our Australian operations in July 1999 through
December 31, 1999 is a reduction in net income of $2.36 million, or $0.05 per
diluted share, and is shown as the cumulative effect of change in accounting
principle on our consolidated statement of income for the year ended December
31, 2000. The pro forma effect had SAB No. 101 been applied retroactively to
1999 would have reduced net income by $2.36 million, or $0.06 per diluted share.
SAB No. 101 would not have effected periods prior to the acquisition of the
Company's Australian operations in July 1999.
As a result of the adoption of Emerging Issues Task Force (EITF) No. 00-10,
"Accounting for Shipping and Handling Fees and Costs," we have reclassified to
operating expenses, for all periods presented, third party costs incurred to
transport production to our sales point to cost of sales, instead of as a
reduction of the related revenues as previously reported. This reclassification
had no effect on previously reported net income. Approximately $6.0 million,
$5.9 million and $3.8 million were reclassified pursuant to EITF No. 00-10 for
2000, 1999 and 1998, respectively.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
------------------------
2000 1999 1998
------ ------ ------
PRODUCTION:
United States
Natural gas (Bcf)........................................ 105.4 87.4 66.6
Oil and condensate (MBbls)............................... 4,090 3,487 3,643
Total production (Bcfe).................................. 130.0 108.3 88.5
Australia(1)
Oil and condensate (MBbls)............................... 1,674 867 --
Total (Bcfe)............................................. 10.0 5.2 --
Total
Natural gas (Bcf)........................................ 105.4 87.4 66.6
Oil and condensate (MBbls)............................... 5,764 4,354 3,643
Total (Bcfe)............................................. 140.0 113.5 88.5
AVERAGE REALIZED PRICES(2):
United States
Natural gas (per Mcf).................................... $ 3.56 $ 2.32 $ 2.25
Oil and condensate (per Bbl)............................. 23.33 16.27 12.75
Australia(1)
Oil and condensate (per Bbl)............................. $30.08 $25.70 $ --
Total
Natural gas (per Mcf).................................... $ 3.56 $ 2.32 $ 2.25
Oil and condensate (per Bbl)............................. 25.29 18.15 12.75
---------------
(1) In July 1999, we acquired oil producing assets offshore Australia.
(2) Average realized prices for natural gas and oil and condensate are presented
net of all applicable transportation expenses, which reduces the realized
price of natural gas by $0.04, $0.05 and $0.04 in 2000, 1999 and 1998,
respectively, and the realized oil and condensate price by $0.27, $0.32 and
$0.34 in 2000, 1999 and 1998, respectively. Average realized prices include
the effect of hedges.
14
18
PRODUCTION. Our total oil and gas production (stated on a natural gas
equivalent basis) increased 23.3% in 2000 and 28.2% in 1999.
Natural Gas. Our 2000 natural gas volumes increased 21% over 1999. The
significant increase was primarily related to acquisitions of producing
properties in South Texas, development projects and the success of our drilling
program. Our acquisition of three producing gas fields in South Texas added 9
Bcfe to our 2000 production volumes. A large part of our production growth in
2000 came from our onshore operations. At year-end 2000, our U.S. onshore
production was 65 MMcfe/d, a significant increase over the 15 MMcfe/d we
averaged in 1999 and the 5.6 MMcfe/d that we averaged in 1998. This significant
increase reflects acquisitions and successful results from our drilling programs
in the Provident City area of Texas and our Broussard Field in southern
Louisiana. The following Gulf of Mexico development projects were also major
contributors: Eugene Island 198/199/202, West Cameron 522 and Main Pass 264.
Gains in production were partially offset by natural declines from other
producing properties. In 1999, our natural gas volumes increased 31% over 1998.
Increased gas production in 1999 was due to projects at East Cameron 286 and
373, and South Marsh Island 141.
In 2001, our natural gas production will show a significant increase as a
result of our recent acquisition of Lariat Petroleum. The properties acquired in
that transaction, which are primarily located in the Anadarko Basin of Oklahoma,
were producing about 60 MMcfe/d as of February 28, 2001.
Crude Oil and Condensate. Our crude oil production in 2000 increased 32%
over 1999 levels. The increase in 2000 oil production primarily relates to the
full-year affect of our acquisition of two producing oil fields in Australia and
development projects in the Gulf of Mexico. During 2000, our Australian oil
production averaged about 4,573 BOPD and accounted for 29% of our total oil
production. Major development projects in the Gulf of Mexico that contributed to
our increased oil production in 2000 were Vermilion 215, Eugene Island
198/199/202, High Island 474 and Main Pass 138 and 264. Our oil production
increased nearly 20% in 1999 over 1998, primarily as a result of our acquisition
in Australia.
REALIZED PRICES. Our average realized price on a per Mcf equivalent basis
in 2000 was $3.72, an increase of 50% over our 1999 average Mcf equivalent price
of $2.48.
Natural Gas. Our average realized gas price in 2000 was $3.56 per Mcf, an
increase of 53% over our 1999 average realized price of $2.32 per Mcf. In 1998,
our average realized gas price was $2.25 per Mcf. Our average realized gas price
in 2000 was negatively affected by our hedging activities, which resulted in a
price that was 88% of what otherwise would have been received without hedging
activities. In 1999, we received 102% of what otherwise would have been received
without hedging activities.
Crude Oil and Condensate. Crude oil and condensate prices in 2000 averaged
$25.29 per barrel. This compares to an average realized price of $18.15 per
barrel in 1999. Our average crude oil price in 2000 was 85% of what would have
been received prior to hedging activities. In 1999, our average crude oil price
was 94% of what would have been received prior to hedging activities. We
realized $12.75 per barrel in 1998, which was 102% of the price that would have
otherwise been received without hedging activities.
NET INCOME AND REVENUES. For 2000, we had net income of $132.3 million, or
$2.93 per diluted share. This compares to net income of $33.2 million, or $0.79
cents per diluted share, in 1999. Revenues for 2000 increased 83% to $526.6
million compared to revenues of $287.9 million in 1999. The increase in net
income and revenues in 2000 was primarily due to sharp increases in commodity
prices coupled with a 23% increase in production volumes
In 1998, we had a net loss of $57.7 million, or $1.55 per diluted share.
Revenues for the period were $199.5 million. Our 1998 financial performance was
adversely affected by a pre-tax, full-cost ceiling test writedown of $105.0
million (resulting in a charge to earnings of $68.3 million after-tax) in the
carrying value of our oil and gas properties. The writedown was primarily due to
low commodity prices at December 31, 1998.
15
19
OPERATING EXPENSES. The table below sets forth our operating expenses for
the three preceding calendar years on a unit of production basis.
YEAR ENDED DECEMBER 31,
------------------------
2000 1999 1998
------ ------ ------
AVERAGE COSTS (PER MCFE):
United States
Lease operating........................................... $0.40 $0.36 $0.40
Production and other taxes................................ 0.04 0.01 --
Transportation............................................ 0.05 0.05 0.04
Depreciation, depletion and amortization.................. 1.41 1.38 1.39
General and administrative (exclusive of stock
compensation).......................................... 0.22 0.13 0.11
Australia(1)
Lease operating........................................... $1.38 $1.35 $ --
Production and other taxes................................ 0.46 0.29 --
Transportation............................................ -- -- --
Depreciation, depletion and amortization.................. 0.74 0.63 --
General and administrative (exclusive of stock
compensation).......................................... 0.06 0.02 --
Total
Lease operating........................................... $0.47 $0.40 $0.40
Production and other taxes................................ 0.07 0.02 --
Transportation............................................ 0.04 0.05 0.04
Depreciation, depletion and amortization.................. 1.37 1.35 1.39
General and administrative (exclusive of stock
compensation).......................................... 0.21 0.13 0.11
---------------
(1) In July 1999, we acquired oil producing assets offshore Australia.
During 2000, our operating expenses increased 37% over 1999, primarily due
to the following reasons:
-- On a unit of production basis, lease operating expense increased 18% to
$0.47 per Mcfe in 2000 compared to $0.40 per Mcfe in 1999. Domestic
lease operating expense increased 11% on a unit of production basis to
$0.40 per Mcfe in 2000 compared to $0.36 per Mcfe in 1999. Australian
lease operating expense, stated on a unit of production basis, was $1.38
per Mcfe in 2000 compared to $1.35 per Mcfe in 1999. Our lease operating
expense increases per Mcfe reflect higher oilfield service costs in the
Gulf of Mexico, relatively higher Australian lease operating expenses
associated with the operations and maintenance of the two floating
production, storage and off-loading vessels (FPSO) and production
downtime due to in-fill drilling operations during the year in
Australia.
-- On a unit of production basis, production and other taxes increased to
$0.07 per Mcfe in 2000 compared to $0.02 per Mcfe in 1999. Domestic
production and other taxes increased to $0.04 per Mcfe in 2000 compared
to $0.01 per Mcfe in 1999 due to increased production onshore, including
the acquisition of three producing gas fields in South Texas during
early 2000. Australian production and other taxes increased to $0.46 per
Mcfe in 2000 compared to $0.29 in 1999 primarily due to higher commodity
prices.
-- As a result of EITF No. 00-10, we have reclassified to operating
expense, for all periods presented, third party costs incurred to
transport production to our sales point instead of as a reduction of the
related revenues as previously reported. See "-- Accounting Policies"
under this Item 7.
-- Depreciation, depletion and amortization expense increased 2% on a unit
of production basis to $1.37 per Mcfe in 2000 compared to $1.35 per Mcfe
in 1999. Our domestic depreciation, depletion and amortization expense
increased 2% on a unit of production basis to $1.41 per Mcfe. The
increase in the domestic DD&A rate is due to several factors, including
increases in the cost of drilling goods and services, platforms and
facilities construction, industry transportation costs and the
completion of several higher cost wells. The Australian DD&A rate
increased 17% on a unit of
16
20
production basis to $0.74 per Mcfe in 2000 compared to $0.63 per Mcfe in
1999. The increase is a result of our unsuccessful drilling activities
in 2000.
-- General and administrative expense, exclusive of stock compensation,
increased to $29 million in 2000 compared to $14.4 million in 1999. On a
unit of production basis, the increase was 62% to $0.21 in 2000 versus
$0.13 in 1999. This increase is due primarily to an increase in
performance-based pay, some non-recurring expenses associated with a
transition to more sophisticated business systems and our growing
workforce. Performance-based compensation, excluding stock compensation
expense, a component of general and administrative expense, increased
from $3.9 million in 1999, or $0.03 per Mcfe, to $12.8 million in 2000,
or $0.09 per Mcfe. The increase in performance-based compensation is a
result of our higher earnings. Performance-based pay is limited by
profitability.
During 1999, our operating expenses decreased 21% over 1998. The decrease
relates primarily to the ceiling test writedown taken during 1998. Exclusive of
the writedown, our operating expenses for 1999 increased 17% as compared to
1998. The following impacted operating expenses in 1999:
-- Lease operating expense, stated on a unit of production basis, was flat
compared to 1998. Domestic lease operating expense decreased 10% on a
unit of production basis to $0.36 per Mcfe in 1999 compared to $0.40 per
Mcfe in 1998. Lower domestic lease operating expense was offset by
Australian lease operating expense of $8.07 per BOE, or $1.35 per Mcfe.
High lease operating expense per Mcfe in Australia is primarily due to
the higher cost of operations and maintenance of the two FPSOs.
-- Production and other taxes of $2.2 million primarily relate to the
production tax on our Australian operations but also includes lease
taxes for domestic onshore production.
-- Depreciation, depletion and amortization expense decreased 3% on a unit
of production basis. Our domestic DD&A rate decreased slightly to $1.38
per Mcfe in 1999 compared to $1.39 per Mcfe in 1998. Absent the ceiling
test writedown taken in 1998, our domestic DD&A rate would have
increased in 1999. The Australian DD&A rate was $0.63 per Mcfe.
-- General and administrative expense was up $4.6 million, or 46%, due
primarily to a larger workforce and an increase in performance-based
pay.
INTEREST EXPENSE AND DIVIDENDS. We incur interest expense on our $125
million principal amount 7.45% Senior Notes due 2007 and on borrowings under our
reserve-based revolving credit facility and money market credit lines.
Outstanding borrowings under these arrangements may vary significantly from
period to period. Dividends are paid on our 6.5% convertible trust preferred
securities we issued in August 1999.
YEAR ENDED DECEMBER 31,
------------------------
2000 1999 1998
------ ------ ------
(IN MILLIONS)
Gross interest expense...................................... $14.7 $13.6 $13.9
Capitalized interest........................................ (5.4) (2.4) (4.4)
----- ----- -----
Net interest expense........................................ 9.3 11.2 9.5
Dividends on preferred securities........................... 9.3 3.6 --
----- ----- -----
Total interest expense and dividends.............. $18.6 $14.8 $ 9.5
===== ===== =====
In 2000, our higher total interest expense was the result of borrowings in
January 2000 to finance our acquisition of three producing properties in South
Texas for $139 million. At year-end 2000, borrowings under our credit facility
and credit lines were only $9 million. Our net interest expense in 1999 was
higher than in 1998 as a result of decreased capitalized interest amounts during
1999 as compared to 1998. The decrease in capitalized interest from 1998 to 1999
is primarily due to the ceiling test writedown recorded at December 31, 1998.
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TAXES. The effective tax rate for the three year period ended December 31,
2000 was 34%, 36% and 35%, respectively. The effective tax rate was less than
statutory tax rate in 2000 because the valuation allowance on the Australian net
operating loss carryforwards was reduced by $2.3 million in 2000 primarily as a
result of a substantial increase in estimated taxable income. Estimates of
future taxable income can be significantly affected by changes in oil and
natural gas prices, estimates of the timing and amounts of future production,
and estimates of future operating and capital costs. The valuation allowance
could be increased in the near term if our estimates of future taxable income
are significantly reduced. If sufficient taxable income is not generated in the
future through operating results, a valuation allowance adjustment would be
recorded as a charge to income.
In conjunction with our acquisition of Lariat in January 2001, we acquired
net operating loss carryforwards of approximately $60 million that, based on
estimates of future taxable income, are expected to be fully utilized within the
next five years.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. We had working capital of $38.1 million as of December
31, 2000. This compares to $35.2 million at the end of 1999 and a deficit of
$8.8 million at the end of 1998. Working capital balances may fluctuate from
year to year to the extent we increase or decrease borrowings under our
revolving credit facility. Historically, we have funded our oil and gas
activities through cash flow from operations, equity capital, public debt and
bank borrowings.
DEBT. In association with our acquisition of three producing gas fields in
South Texas in early 2000, we borrowed $112 million through our reserve-based
revolving credit facility. At year-end 2000, only $4 million of outstanding debt
remained under our credit facility and an additional $5 million was outstanding
under our money market lines of credit. At year-end 2000, our long-term debt was
$133.7 million, which includes our 7.45% Senior Notes due 2007 of $124.7
million.
On January 23, 2001, we acquired Lariat Petroleum for total consideration
of approximately $333 million, inclusive of the assumption of debt and certain
other obligations of Lariat. The consideration included 1.9 million shares of
our common stock. We financed the cash portion of the consideration under a new
reserve-based revolving credit facility obtained on January 23, 2001 with The
Chase Manhattan Bank, as Agent.
The banks participating in the new facility have committed to lend the
Company up to $425 million. The amount available under the facility is subject
to a calculated borrowing base determined by banks holding 75% of the aggregate
commitments, which is reduced by the aggregate outstanding principal amount of
any senior notes issued by us (currently $300 million; see discussion of 7 5/8%
Senior Notes due 2011 below). The borrowing base is currently $510 million and
is redetermined at least semi-annually. No assurances can be given that the
banks will not elect to redetermine the borrowing base in the future. The new
facility contains restrictions on the payment of dividends and the incurrence of
debt as well as other customary covenants and restrictions. The new facility
matures on January 23, 2004. At February 28, 2001 we had $160 million available
under our credit facility and had outstanding borrowings of $50 million.
We also have money market lines of credit with various banks in an amount
limited by the credit facility to $40 million. As of February 28, 2001, there
were no borrowings outstanding under these lines of credit.
On February 22, 2001, we placed $175 Million of 7 5/8% Senior Notes due
2011. The offering was done under an existing shelf registration statement. Net
proceeds from the sale of the senior notes were used to repay outstanding
indebtedness under our revolving credit facility. The notes were issued at
99.931% of par to yield 7.635%, with interest payable on each March 1 and
September 1, commencing September 1, 2001.
CASH FLOW FROM OPERATIONS. Our net cash flow from operations for 2000
increased 71% over 1999 to $316.4 million. The increase is due to a significant
increase in commodity prices and higher production volumes, offset by higher
operating expenses. This compares to cash flow from operations in 1999 of $184.9
million. Net cash flow from operations before changes in operating assets and
liabilities for 2000
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was $383.5 million compared to $205.6 million in 1999. The increase in net cash
flow from operations before changes in operating assets and liabilities in 2000
over 1999 is primarily attributable to higher commodity prices and production
volumes, offset by increased operating expenses.
CAPITAL EXPENDITURES. In 2000, our capital spending totaled $379 million.
The largest spending category was acquisitions, reflecting our first quarter
2000 purchase of three producing gas fields in South Texas for $139 million.
Other categories included: development, $139 million, and exploration, $100
million. Our 2000 capital expenditures included approximately $20 million for
international activities. Total capital spending in 1999 was $209.8 million. Our
1999 capital spending program included $51.5 million for exploration, $72.3
million for exploitation and development projects and $86 million for property
acquisitions.
We have budgeted $711 million for capital spending in 2001, including $333
million for the purchase of Lariat. Approximately $111 million has been budgeted
for domestic exploration projects and $246 million for domestic exploitation and
development drilling and the construction of platforms, facilities and
pipelines. International spending in 2001 is estimated at $21 million.
Acquisitions are opportunistic and are not budgeted under our capital program.
We continue to pursue attractive acquisition opportunities, however, the timing,
size and purchase price of acquisitions are unpredictable. We anticipate that
our capital expenditure budget for 2001 will be funded principally from cash
flow from operations and working capital. We do not anticipate additional
borrowings under our credit facility and money market lines of credit during
2001 unless we make another significant acquisition. Actual levels of capital
expenditures may vary significantly due to many factors, including drilling
results, oil and gas prices, industry conditions, the prices and availability of
goods and services and the extent to which proved properties are acquired.
HEDGING
We utilize and expect to continue to utilize hedging transactions with
respect to a portion of our oil and gas production. These derivative financial
instruments are used to hedge our exposure to changes in the market price of
natural gas and crude oil and to achieve more predictable cash flow. 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 our
hedging transactions to date were carried out in the over-the-counter market. We
account for these transactions as hedging activities and, accordingly, gains or
losses are included in oil and gas revenues when the hedged production is
delivered. Neither the hedging contracts nor the unrealized gains or losses on
these contracts are recognized in our financial statements. Effective January 1,
2001, we adopted SFAS No. 133. This standard establishes new accounting and
reporting standards for derivative instruments and for hedging activities. See
"-- Accounting Policies" under this Item 7.
During 2000, approximately 47% of our equivalent production was subject to
hedge positions as compared to 55% in 1999 and 61% in 1998. The following tables
set forth the hedging transactions that we have entered into with respect to a
portion of our estimated natural gas and oil and condensate production through
March 2003. We continue to evaluate additional hedging transactions for 2001 and
future years.
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NATURAL GAS. As of December 31, 2000, we had entered into the commodity
price hedging contracts set forth in the table below with respect to our 2001
and 2002 U.S. Gulf Coast natural gas production. These hedging transactions are
settled based upon the average of the reported settlement prices on the NYMEX
for the last three trading days or occasionally, the penultimate trading day of
a particular contract month (the "settlement price").
NYMEX CONTACT PRICE PER MMBTU
--------------------------------------------------
COLLARS
VOLUME IN SWAPS -------------------------- FLOOR FAIR MARKET
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
--------------------------- --------- --------- ----------- ------------ --------- ---------------
January 2001 -- March 2001
Price Swap Contracts..... 10,510 $3.29 -- -- -- $ (64.5 Million)
Collar Contracts......... 5,980 -- $2.75-$7.00 $3.21-$10.80 -- $ (20.5 Million)
April 2001 -- June 2001
Price Swap Contracts..... 7,380 $3.42 -- -- -- $ (17.8 Million)
Collar Contracts......... 9,080 -- $2.75-$4.50 $3.21-$6.15 -- $ (9.3 Million)
July 2001 -- September 2001
Price Swap Contracts..... 2,780 $5.17 -- -- -- $ (0.5 Million)
Collar Contracts......... 9,400 -- $3.50-$4.50 $3.85-$6.00 -- $ (6.4 Million)
October 2001 -- December
2001
Price Swap Contracts..... 1,770 $5.23 -- -- -- $ (0.3 Million)
Collar Contracts......... 900 -- $4.00-$4.50 $5.75-$6.00 -- $ (0.3 Million)
Floor Contracts.......... 900 -- -- -- $4.54 $ 0.2 Million
January 2002 -- December
2002
Collar Contracts......... 4,800 -- $4.00 $4.80-$5.15 -- $ (0.4 Million)
---------------
(1) Except for January 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at December
31, 2000. Because January 2001 NYMEX futures contracts expired on December
27, 2000, the fair market value of January 2001 hedging contracts represents
the actual settlement value of such contracts.
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Subsequent to December 31, 2000, we entered into additional commodity price
hedging contracts with respect to our 2001 and 2002 U.S. Gulf Coast natural gas
production as follows:
NYMEX CONTACT PRICE PER MMBTU
--------------------------------------
COLLARS
VOLUME IN SWAPS --------------------------
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS
------------------------------------------------------ --------- --------- ----------- ------------
July 2001 -- September 2001
Price Swap Contracts................................ 2,600 $5.07 -- --
Collar Contracts.................................... 600 -- $4.75 $5.55
October 2001 -- December 2001
Price Swap Contracts................................ 1,000 $5.10 -- --
Collar Contracts.................................... 1,600 -- $4.75 $5.55
January 2002 -- December 2002
Collar Contracts.................................... 2,100 -- $3.75-$4.25 $5.50-$8.10
We believe there is no material basis risk with respect to our Gulf Coast
natural gas hedging contracts because substantially all of our Gulf Coast
natural gas production is sold under spot contracts that have historically
correlated to the reference price.
In connection with our acquisition of Lariat Petroleum in January 2001 we
inherited the natural gas hedges set forth in the table below that had been
entered into by Lariat during 2000. These hedging transactions are settled based
upon reported sales prices of natural gas delivered into those pipelines at the
physical locations where we sell our production in Oklahoma.
CONTACT PRICE PER MMBTU
--------------------------------------
COLLARS
VOLUME IN SWAPS --------------------------
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS
------------------------------------------------------ --------- --------- ----------- ------------
January 2001 -- March 2001
Price Swap Contracts................................ 1,950 $6.04 -- --
Collar Contracts.................................... 900 -- $2.27 $2.69
April 2001 -- June 2001
Price Swap Contracts................................ 1,860 $3.97 -- --
Collar Contracts.................................... 610 -- $2.27 $2.69
July 2001 -- September 2001
Price Swap Contracts................................ 2,420 $4.11 -- --
October 2001 -- December 2001
Price Swap Contracts................................ 2,420 $4.11 -- --
January 2002 -- December 2002
Price Swap Contracts................................ 3,650 $2.62 -- --
January 2003 -- March 2003
Price Swap Contracts................................ 900 $2.61 -- --
We believe there is no material basis risk with respect to our Oklahoma
natural gas hedging contracts because all of the above trades are settled
against the same pipelines into which our production in Oklahoma is sold.
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OIL AND CONDENSATE. As of December 31, 2000, we had entered into commodity
price hedging contracts with respect to our U.S. Gulf Coast oil production for
2001 and 2002 as follows:
NYMEX CONTRACT PRICE PER BBL
---------------------------------------------------------
COLLARS
VOLUME IN SWAPS ----------------------------- FLOOR FAIR MARKET
PERIOD BBLS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
------------------------- --------- --------- ------------- ------------- ------------- -------------
January 2001 -- March
2001
Price Swap Contracts... 540,000 $21.99 -- -- -- $(2.9 Million)
Collar Contracts....... 270,000 -- $25.00 $30.05-$30.75 -- $ 0.2 Million
Floor Contracts........ 238,500 -- -- -- $22.17-$29.58 $ 0.6 Million
April 2001 -- June 2001
Price Swap Contracts... 436,800 $22.80 -- -- -- $(1.1 Million)
Collar Contracts....... 364,000 -- $25.00-$27.25 $30.05-$30.75 -- $ 0.6 Million
Floor Contracts........ 186,550 -- -- -- $22.17-$28.28 $ 0.5 Million
July 2001 -- September
2001
Price Swap Contracts... 391,000 $23.88 -- -- -- $(0.3 Million)
Collar Contracts....... 414,000 -- $24.00-$26.25 $27.30-$32.45 -- $ 0.6 Million
Floor Contracts........ 207,000 -- -- -- $22.17-$27.04 $ 0.6 Million
October 2001 -- December
2001
Price Swap Contracts... 386,400 $23.24 -- -- -- $(0.3 Million)
Collar Contracts....... 345,000 -- $24.00-$25.25 $27.30-$30.75 -- $ 0.3 Million
Floor Contracts........ 262,200 -- -- -- $22.17-$26.00 $ 0.9 Million
January 2002 -- March
2002
Collar Contracts....... 517,500 -- $22.00-$25.00 $25.75-$30.75 -- $ 0.2 Million
April 2002 -- June 2002
Collar Contracts....... 455,000 -- $22.00-$25.00 $25.75-$30.75 -- $ 0.1 Million
July 2002 -- September
2002
Collar Contracts....... 345,000 -- $23.00-$25.00 $26.75-$30.75 -- $ 0.3 Million
October 2002 -- December
2002
Collar Contracts....... 184,000 -- $25.00 $28.00-$30.75 -- $ 0.2 Million
---------------
(1) Except for January 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at December
31, 2000. Because January 2001 NYMEX futures contracts expired on December
19, 2000, the fair market value of January 2001 hedging contracts represents
the actual settlement value of such contracts.
Because substantially all of our U.S. Gulf Coast oil production is sold
under spot contracts that have historically correlated to the NYMEX West Texas
Intermediate price, we believe that we have no material basis risk with respect
to these transactions. The actual cash price we receive, however, generally is
about $2.00 per barrel less than the NYMEX West Texas Intermediate price when
adjusted for location and quality differences.
With respect to any particular swap transaction, the counterparty is
required to make a payment to us in the event that the settlement price for any
settlement period is less than the swap price for such transaction, and we are
required to make payment to the counterparty in the event that the settlement
price for any settlement period is greater than the swap price for such
transaction. For any particular collar transaction, the counterparty is required
to make a payment to us if the settlement price for any settlement period is
below the floor price for such transaction, and we are required to make payment
to the counterparty if the settlement price for any settlement period is above
the ceiling price for such transaction. For any particular floor transaction,
the counterparty is required to make a payment to us if the settlement price for
any settlement period is below the floor price for such transaction. We are not
required to make any payment in connection with the settlement of a floor
transaction.
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REGULATION
WE ARE SUBJECT TO COMPLEX LAWS THAT CAN AFFECT THE COST, MANNER OR
FEASIBILITY OF DOING BUSINESS. Exploration, development, production and sale of
oil and gas are subject to extensive federal, state, local and international
regulation. We may be required to make large expenditures to comply with
environmental and other governmental regulations. Matters subject to regulation
include:
-- discharge permits for drilling operations;
-- drilling bonds;
-- reports concerning operations;
-- the spacing of wells;
-- unitization and pooling of properties; and
-- taxation.
Under these laws, we could be liable for personal injuries, property
damage, oil spills, discharge of hazardous materials, remediation and clean-up
costs and other environmental damages. Failure to comply with these laws also
may result in the suspension or termination of our operations and subject us to
administrative, civil and criminal penalties. Moreover, these laws could change
in ways that substantially increase our costs. Any such liabilities, penalties,
suspensions, terminations or regulatory changes could have a material adverse
effect on our financial condition and results of operations.
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL
GAS. Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to several laws enacted by
Congress and the regulations promulgated under these laws by the FERC. In the
past, the federal government has regulated the prices at which gas could be
sold. Congress removed all price and non-price controls affecting wellhead sales
of natural gas effective January 1, 1993. Congress could, however, reenact price
controls in the future.
Our sales of natural gas are affected by the availability, terms and cost
of transportation. The price and terms for access to pipeline transportation are
subject to extensive federal and state regulation. From 1985 to the present,
several major regulatory changes have been implemented by Congress and the FERC
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC is continually proposing and implementing new rules and
regulations affecting those segments of the natural gas industry, most notably
interstate natural gas transmission companies, that remain subject to the FERC's
jurisdiction. These initiatives may also affect the intrastate transportation of
gas under certain circumstances. The stated purpose of many of these regulatory
changes is to promote competition among the various sectors of the natural gas
industry and these initiatives generally reflect more light-handed regulation.
The ultimate impact of the complex rules and regulations issued by the FERC
since 1985 cannot be predicted. In addition, many aspects of these regulatory
developments have not become final but are still pending judicial and FERC final
decisions. We cannot predict what further action the FERC will take on these
matters. Some of the FERC's more recent proposals may, however, adversely affect
the availability and reliability of interruptible transportation service on
interstate pipelines. We do not believe that we will be affected by any action
taken materially differently than other natural gas producers, gatherers and
marketers with which we compete.
The Outer Continental Shelf Lands Act, or OCSLA, requires that all
pipelines operating on or across the Outer Continental Shelf, or the Shelf,
provide open-access, non-discriminatory service. Historically, the FERC has
opted not to impose regulatory requirements under its OCSLA authority on
gatherers and other entities outside the reach of its Natural Gas Act
jurisdiction. However, the FERC recently issued Order No. 639, requiring that
virtually all non-proprietary pipeline transporters of natural gas on the Shelf
report information on their affiliations, rates and conditions of service. These
reporting requirements apply, in certain circumstances, to operators of
production platforms and other facilities on the Shelf with respect to
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gas movements across such facilities. In addition, the FERC retains authority
under OCSLA to exercise jurisdiction over entities outside the reach of its
Natural Gas Act jurisdiction if necessary to ensure non-discriminatory access to
service on the Shelf. We do not believe that any FERC action taken under OCSLA
will affect us in a way that materially differs from the way it affects other
natural gas producers, gatherers and marketers with which we compete.
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 REGULATION OF SALES AND TRANSPORTATION OF CRUDE OIL. Our sales of
crude oil, condensate and natural gas liquids are currently not regulated and
are made at market prices. In a number of instances, however, the ability to
transport and sell such products are dependent on pipelines whose rates, terms
and conditions of service are subject to FERC jurisdiction under the Interstate
Commerce Act. Certain regulations implemented by the FERC in recent years could
result in an increase in the cost of transportation service on certain petroleum
products pipelines. However, we do not believe that these regulations affect us
any differently than other natural gas producers.
FEDERAL LEASES. The majority of our U.S. operations are located on federal
oil and gas leases, which are administered by the MMS. These leases are issued
through competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to 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 Shelf to meet stringent
engineering and construction specifications. The MMS also has regulations
restricting the flaring or venting of natural gas, and has proposed to amend
such regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization. Similarly, the MMS has promulgated other regulations
governing the plugging and abandonment of wells located offshore and the removal
of all production facilities. To cover the various obligations of lessees on the
Shelf, 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. We are currently exempt
from the supplemental bonding requirements of the MMS. Under certain
circumstances, the MMS may require that our operations on federal leases be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition, cash flows and results of operations.
The MMS recently issued a final rule that amended its regulations governing
the calculation of royalties and the valuation of crude oil produced from
federal leases. This rule provides that the MMS will collect royalties based
upon the market value of oil produced from federal leases. The lawfulness of the
new rule has been challenged in federal court. We cannot predict what action the
MMS will take on this matter. We believe that these rules, if adopted as
proposed, will not have a material effect on our financial position, cash flows
or results of operations.
STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION. We own interests in
properties located onshore Louisiana, Texas, New Mexico and Oklahoma. We also
own interests in properties in the state waters offshore Texas and Louisiana.
These states regulate drilling and operating activities by requiring, among
other things, drilling permits, bonds and reports concerning operations. The
laws of these states also govern a number of environmental and conservation
matters, including the handling and disposing of waste materials, unitization
and pooling of oil and gas properties and establishment of maximum rates of
production from oil and gas wells. Some states prorate production to the market
demand for oil and gas.
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ENVIRONMENTAL REGULATIONS. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Failure to comply with these
laws and regulations may result in the assessment of administrative, civil and
criminal penalties or the imposition of injunctive relief. Public interest in
the protection of the environment has increased dramatically in recent years.
Both onshore and 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 onshore or offshore drilling or imposes environmental protection
requirements that result in increased costs to the oil and gas industry in
general, our business and prospects could be adversely affected.
The Oil Pollution Act of 1990, or OPA, imposes regulations on "responsible
parties" related to the prevention of oil spills and liability for damages
resulting from such spills in U.S. waters. A "responsible party" includes the
owner or operator of an onshore facility, vessel or pipeline, or the lessee or
permittee of the area in which an offshore facility is located. OPA assigns
liability to each responsible party for oil removal costs and a variety of
public and private damages. While liability limits apply in some circumstances,
a party cannot take advantage of liability limits if the spill was caused by
gross negligence or willful misconduct or resulted from violation of a federal
safety, construction or operating regulation. If the party fails to report a
spill or to cooperate fully in the cleanup, liability limits likewise do not
apply. Even if applicable, the liability limits for offshore facilities require
the responsible party to pay all removal costs, plus up to $75 million in other
damages for offshore facilities and pay up to $350 million for onshore
facilities. Few defenses exist to the liability imposed by OPA. Failure to
comply with ongoing requirements or inadequate cooperation during a spill event
may subject a responsible party to administrative, civil or criminal enforcement
actions. In addition to OPA, our discharges to waters of the U.S. are further
limited by the federal Clean Water Act, or CWA, and analogous state laws. CWA
prohibits any discharge into waters of the United States except in strict
conformance with permits issued by federal and state governmental agencies.
Failure to comply with CWA, including discharge limits on permits issued
pursuant to CWA, may also result in administrative, civil or criminal
enforcement actions. OPA and CWA also impose other requirements, such as the
preparation of an oil spill response plan. We have all required spill response
plans in place.
OPA requires responsible parties to demonstrate proof of financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill. Under OPA and a final rule adopted
by the MMS in August 1998, responsible parties of covered offshore facilities
that have a worst case oil spill of more than 1,000 barrels must demonstrate
financial assurance in amounts ranging from at least $10 million in state waters
to at least $35 million in federal waters, with higher amounts of up to $150
million based on a covered facility's potential worst case oil spill discharge
volume or if a formal risk assessment indicates that an amount higher than $35
million should be required. We believe we are in compliance with OPA and the MMS
rule for demonstrating financial responsibility for our covered facilities.
OCSLA authorizes regulations relating to safety and environmental
protection applicable to lessees and permittees operating on the Shelf. Specific
design and operational standards may apply to vessels, rigs, platforms, vehicles
and structures operating or located on the Shelf. Violations of lease conditions
or regulations issued pursuant to OCSLA can result in substantial
administrative, 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 Resource Conservation and Recovery Act, or RCRA, generally does not
regulate most wastes generated by the exploration and production of oil and gas.
RCRA specifically excludes from the definition of hazardous waste "drilling
fluids, produced waters and other wastes associated with the exploration,
development or production of crude oil, natural gas or geothermal energy." From
time to time, however, legislation has been proposed in Congress 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 our operating costs, as well as those of the oil and
gas industry in general. Moreover, ordinary
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industrial wastes, such as paint wastes, waste solvents, laboratory wastes and
waste oils, may be regulated as hazardous waste.
The Comprehensive Environmental Response, Compensation, and Liability Act,
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. Persons who are or were responsible for releases of hazardous
substances under the Superfund law 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. We currently own or lease onshore properties that
have been used for the exploration and production of oil and gas for a number of
years. These recently acquired onshore properties have been operated by third
parties whose treatment and disposal or release of hydrocarbons or other wastes
was not under our control. These properties and any wastes that may have been
disposed or released on them may be subject to the Superfund law, RCRA and
analogous state laws, and we potentially could be required to remediate such
properties.
We believe that we are in substantial compliance with current applicable
U.S. federal, state and local environmental laws and regulations and that
continued compliance with existing requirements will not have a material adverse
effect on our financial position, cash flows or results of operations. Our
foreign operations are potentially subject to similar governmental controls and
restrictions relating to the environment. We believe that we are in substantial
compliance with any such foreign requirements pertaining to the environment.
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 or regulations will not be discovered.
OTHER FACTORS AFFECTING OUR BUSINESS
OIL AND GAS PRICES FLUCTUATE WIDELY, AND LOW PRICES FOR AN EXTENDED PERIOD
OF TIME ARE LIKELY TO HAVE A MATERIAL ADVERSE IMPACT ON OUR BUSINESS. Our
revenues, profitability and future growth depend substantially on prevailing
prices for oil and gas. These prices also affect the amount of cash flow
available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under our credit facility is
subject to periodic redeterminations based in part on changing expectations of
future prices. Lower prices may also reduce the amount of oil and gas that we
can economically produce.
Prices for oil and gas fluctuate widely. Among the factors that can cause
fluctuations are:
-- the domestic and foreign supply of oil and natural gas;
-- weather conditions;
-- the price of foreign imports;
-- world-wide economic conditions;
-- political conditions in oil and gas producing regions;
-- the level of consumer demand;
-- domestic and foreign governmental regulations; and
-- the price and availability of alternative fuels.
OUR USE OF HEDGING TRANSACTIONS FOR A PORTION OF OUR OIL AND GAS PRODUCTION
MAY LIMIT FUTURE REVENUES FROM PRICE INCREASES AND RESULT IN SIGNIFICANT
FLUCTUATIONS IN OUR NET INCOME AND STOCKHOLDERS' EQUITY. We use hedging
transactions with respect to a portion of our oil and gas production to achieve
more predictable cash flow and to reduce our exposure to price fluctuations.
While the use of hedging transactions limits the downside risk of price
declines, their use may also limit future revenues from price increases.
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We adopted Statement of Financial Accounting Standards (SFAS) No. 133 as of
January 1, 2001. As a result of adopting SFAS No. 133, our stockholders' equity
and net income may fluctuate significantly from period to period. SFAS No. 133
generally requires us to record each derivative instrument as an asset or
liability measured at its fair value. We recorded an initial adjustment loss of
$4.8 million to net income and a $74.2 million loss in the other comprehensive
loss component of stockholders' equity. Each quarter we must similarly record
changes in the value of our hedges, which could result in significant
fluctuations in net income and stockholders' equity from period to period. See
Note 3 -- "Recent Adoption of SFAS No. 133" to our consolidated financial
statements.
OUR FUTURE SUCCESS DEPENDS ON OUR ABILITY TO REPLACE RESERVES THAT WE
PRODUCE. Our future success depends on our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. As is generally the case
in the Gulf Coast region, our producing properties in that region usually have
high initial production rates, followed by steep declines. As a result, we must
locate and develop or acquire new oil and gas reserves to replace those being
depleted by production. We must do this even during periods of low oil and gas
prices when it may be difficult to raise the capital necessary to finance these
activities. Without successful exploration or acquisition activities, our
reserves, production and revenues will decline rapidly. We cannot assure you
that we will be able to find and develop or acquire additional reserves at an
acceptable cost.
SUBSTANTIAL CAPITAL IS REQUIRED TO REPLACE AND GROW RESERVES. We make, and
will continue to make, substantial expenditures to find, develop, acquire and
produce oil and gas reserves. We believe that we will have sufficient cash
provided by operating activities and borrowings under our credit facility to
fund planned capital expenditures in 2001. If, however, lower oil and gas prices
or operating difficulties result in our cash flow from operations being less
than expected or limit our ability to borrow under our credit facility, we may
be unable to expend the capital necessary to undertake or complete our drilling
program unless we raise additional funds through debt or equity financings. We
cannot assure you that debt or equity financing, cash generated by operations or
borrowing capacity will be available to meet these requirements.
RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN AND DEPEND ON MANY ASSUMPTIONS
THAT MAY TURN OUT TO BE INACCURATE. Estimating accumulations of oil and gas is
complex and is not exact because of the numerous uncertainties inherent in the
process. The process relies on interpretations of available geologic, geophysic,
engineering and production data. The extent, quality and reliability of this
data can vary. The process also requires certain economic assumptions, some of
which are mandated by the SEC, such as oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
accuracy of a reserve estimate is a function of:
-- the quality and quantity of available data;
-- the interpretation of that data;
-- the accuracy of various mandated economic assumptions; and
-- the judgment of the persons preparing the estimate.
Our proved reserve information set forth in this report is based on
estimates we prepared. Estimates prepared by others might differ materially from
our estimates.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from our estimates. Any significant variance
could materially affect the quantities and present value of our reserves. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development and prevailing oil and gas
prices. Our reserves may also be susceptible to drainage by operators on
adjacent properties.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved oil and gas reserves. In
accordance with SEC requirements, we generally base the estimated discounted
future net cash flows from proved reserves on prices and costs on the date of
the
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estimate. Actual future prices and costs may be materially higher or lower than
the prices and costs as of the date of the estimate. For example, future
after-tax net cash flows attributable to our natural gas reserves were estimated
by using a year-end 2000 base price of $9.52 per Mcf. On March 16, 2001, that
base price was $4.92 per Mcf.
IF OIL AND GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE
WRITEDOWNS. There is a risk that we will be required to writedown the carrying
value of our oil and gas properties when oil and gas prices are low or if we
have substantial downward adjustments to our estimated proved reserves,
increases in our estimates of development costs or deterioration in our
exploration results.
We capitalize the costs to acquire, find and develop our oil and gas
properties. Under the full cost accounting method, the net capitalized costs of
our oil and gas properties may not exceed the present value of estimated future
net cash flows from proved reserves, using period end oil and gas prices and a
10% discount factor, plus the lower of cost or fair market value of unproved
properties. If net capitalized costs of our oil and gas properties exceed this
limit, we must charge the amount of this excess to earnings. This type of charge
will not affect our cash flow from operating activities, but it will reduce the
book value of our stockholders' equity. We review the carrying value of our
properties quarterly, based on prices in effect as of the end of each quarter or
as of the time of reporting our results. The carrying value of oil and gas
properties is computed on a country-by-country basis. Therefore, while our
properties in one country may be subject to a writedown, our properties in other
countries could be unaffected. Once incurred, a writedown of oil and gas
properties is not reversible at a later date even if oil or gas prices increase.
WE MAY BE SUBJECT TO RISKS IN CONNECTION WITH ACQUISITIONS. The successful
acquisition of producing properties requires an assessment of several factors,
including:
-- recoverable reserves;
-- future oil and gas prices;
-- operating costs; and
-- potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection
with these assessments, we perform a review of the subject properties that we
believe to be generally consistent with industry practices. Our review will not
reveal all existing or potential problems nor will it permit us to become
sufficiently familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every platform or well,
and structural and environmental problems are not necessarily observable even
when an inspection is undertaken. Even when problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of the problems. We are often not entitled to contractual
indemnification for environmental liabilities and acquire properties on an "as
is" basis.
COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO
CONDUCT OPERATIONS. 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 these properties. Many of our competitors have
financial resources that are substantially greater than ours, which may
adversely affect our ability to compete with these companies.
DRILLING IS A HIGH-RISK ACTIVITY. Our future success will depend on the
success of our drilling program. In addition to the numerous operating risks
described in more detail below, these activities involve the risk that no
commercially productive oil or gas reservoirs will be discovered. In addition,
we often are uncertain as to the future cost or timing of drilling, completing
and producing wells.
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Furthermore, our drilling operations may be curtailed, delayed or canceled as a
result of a variety of factors, including:
-- unexpected drilling conditions;
-- pressure or irregularities in formations;
-- equipment failures or accidents;
-- adverse weather conditions;
-- compliance with governmental requirements; and
-- shortages or delays in the availability of drilling rigs and the
delivery of equipment.
THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT CAN CAUSE
SUBSTANTIAL LOSSES; INSURANCE MAY NOT PROTECT US AGAINST ALL THESE RISKS. These
risks include:
-- fires;
-- explosions;
-- blow-outs;
-- uncontrollable flows of oil, gas, formation water or drilling fluids;
-- natural disasters;
-- pipe or cement failures;
-- casing collapses;
-- embedded oilfield drilling and service tools;
-- abnormally pressured formations; and
-- environmental hazards such as oil spills, natural gas leaks, pipeline
ruptures and discharges of toxic gases.
If any of these events occur, we could incur substantial losses as a result
of:
-- injury or loss of life;
-- severe damage to and destruction of property, natural resources and
equipment;
-- pollution and other environmental damage;
-- clean-up responsibilities;
-- regulatory investigation and penalties;
-- suspension of our operations; and
-- repairs to resume operations.
If we experience any of these problems, our ability to conduct operations
could be adversely affected.
Offshore operations are subject to a variety of operating risks peculiar to
the marine environment, such as capsizing, collisions and damage or loss from
hurricanes or other adverse weather conditions. These conditions can cause
substantial damage to facilities and interrupt production. As a result, we could
incur substantial liabilities that could reduce or eliminate the funds available
for our drilling and development programs and acquisitions, or result in loss of
properties.
We maintain insurance against some, but not all, of these potential risks
and losses. We may elect not to obtain insurance if we believe that the cost of
available insurance is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully covered by
insurance, it could adversely affect us.
WE HAVE RISKS ASSOCIATED WITH OUR FOREIGN OPERATIONS. We continue to
evaluate and pursue new opportunities for international expansion in areas where
we can use our core competencies. To date, we have expanded our operations to
Australia and China.
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Ownership of property interests and production operations in areas outside
the United States is subject to the various risks inherent in foreign
operations. These risks may include:
-- currency restrictions and exchange rate fluctuations;
-- loss of revenue, property and equipment as a result of expropriation,
nationalization, war or insurrection;
-- increases in taxes and governmental royalties;
-- renegotiation of contracts with governmental entities and
quasi-governmental agencies;
-- change in laws and policies governing operations of foreign-based
companies;
-- labor problems; and
-- other uncertainties arising out of foreign government sovereignty over
our international operations.
Our international operations may also be adversely affected by laws and
policies of the United States affecting foreign trade, taxation and investment.
In addition, in the event of a dispute arising from foreign operations, we may
be subject to the exclusive jurisdiction of foreign courts or may not be
successful in subjecting foreign persons to the jurisdiction of the courts of
the United States.
OTHER INDEPENDENT OIL AND GAS COMPANIES' LIMITED ACCESS TO CAPITAL MAY
CHANGE OUR EXPLORATION AND DEVELOPMENT PLANS. Many independent oil and gas
companies have limited access to the capital necessary to finance their
activities. As a result, some of the other working interest owners of our wells
may be unwilling or unable to pay their share of the costs of projects as they
become due. These problems could cause us to change, suspend or terminate our
drilling and development plans with respect to the affected project.
FORWARD-LOOKING INFORMATION
This report contains information that is forward-looking or relates to
anticipated future events or results such as production targets, anticipated
production rates, planned capital expenditures, the availability of capital
resources to fund capital expenditures, estimates of proved reserves and the
estimated present value of such reserves, wells planned to be drilled in the
future, our financial position, business strategy and other plans and objectives
for future operations. Although we believe that the expectations reflected in
this information are reasonable, this information is based upon assumptions and
anticipated results that are subject to numerous uncertainties. Actual results
may vary significantly from those anticipated due to many factors, including
drilling results, oil and gas prices, industry conditions, the prices of goods
and services, the availability of drilling rigs and other support services the
availability of capital resources and other factors affecting our business
described above under the captions "Regulation" and "Other Factors Affecting Our
Business." All written and oral forward-looking statements attributable to us or
persons acting on our behalf are expressly qualified in their entirety by such
factors.
COMMONLY USED OIL AND GAS TERMS
Below are explanations of some commonly used terms in the oil and gas
business.
BASIS RISK. The risk associated with the sales point price for oil or gas
production varying from the reference (or settlement) price for a particular
hedging transaction.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
BCF. Billion cubic feet.
BCFE. Billion cubic feet equivalent, determined using the ratio of six Mcf
gas to one Bbl of crude oil, condensate or natural gas liquids.
BOPD. Barrels of crude oil or other liquid hydrocarbons per day.
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BTU. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
COMPLETION. The installation of permanent equipment for the production of
oil or natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
DEVELOPED ACREAGE. The number of acres that are allocated or assignable to
producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or
natural gas field to the depth of a stratigraphic horizon known to be
productive, including a well drilled to find and produce probable or possible
reserves (an EXPLOITATION WELL).
DRY HOLE OR WELL. A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
EXPLORATORY WELL. A well drilled to find and produce oil or natural gas
reserves that is not a development well.
FARM-IN OR FARM-OUT. An agreement whereunder the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in,"
while the interest transferred by the assignor is a "farm-out."
FERC. The Federal Energy Regulatory Commission.
FIELD. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature or
stratigraphic condition.
FINDING COSTS. Costs associated with acquiring and developing proved oil
and gas reserves that are capitalized by the Company under generally accepted
accounting principles.
GAS LIFT. The process of injecting natural gas into the wellbore to
facilitate the flow of produced fluids from the reservoir to the production
train.
GROSS ACRES OR GROSS WELLS. The total acres or wells in which a working
interest is owned.
LIQUIDS. Crude oil, condensate and natural gas liquids.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
MCF. One thousand cubic feet.
MCFE. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
MMS. The Minerals Management Service of the United States Department of
the Interior.
MMBBLS. One million barrels of crude oil or other liquid hydrocarbons.
MMCF. One million cubic feet.
MMCF/D. One million cubic feet per day.
MMCFE. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange.
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POSSIBLE RESERVES. Reserves similar to probable reserves but that are less
likely to be recovered than not.
PRESENT VALUE. When used with respect to oil and natural gas reserves, the
estimated value of future gross revenues (estimated in accordance with the
requirements of the SEC) to be generated from the production of proved reserves,
net of estimated production and future development costs, using prices and costs
in effect as of the date indicated, without giving effect to nonproperty related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
PROBABLE RESERVES. Reserves which analysis of drilling, geological,
geophysical and engineering data does not demonstrate to be proved under current
technology and existing economic conditions, but where such analysis suggests
the likelihood of their existence and future recovery.
PRODUCTIVE WELL. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
TURNKEY DRILLING CONTRACT. A fixed rate contract pursuant to which the
drilling contractor generally bears the risk of loss for unbudgeted
contingencies.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
WORKOVER. Operations on a producing well to restore or increase
production.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk from changes in oil and gas prices, interest
rates and foreign currency exchange rates as discussed below.
OIL AND GAS PRICES
As independent oil and gas producer, our revenue, profitability, access to
capital and future rate of growth are substantially dependent upon the
prevailing prices of natural gas, crude oil and hydrocarbon condensate.
Prevailing prices for such commodities are subject to wide fluctuation in
response to relatively minor changes in supply and demand and a variety of
additional factors beyond our control. We utilize and expect to continue to
utilize hedging transaction with respect to a portion of our oil and gas
production to achieve more predictable cash flow, as well as to reduce our
exposure to price fluctuations. While hedging limits the downside risk of
adverse price movements, it may also limit future revenues from favorable price
movements. For a further discussion of our hedging activities, see the
information under the caption "Hedging" in Item 7 of this report.
INTEREST RATES
At December 31, 2000, we had approximately $125 million of outstanding
long-term debt (7.45% Senior Notes due 2007) subject to a fixed rate of
interest. Additionally, we had $144 million of convertible trust preferred
securities bearing a fixed dividend rate of 6.5% and $9 million outstanding
under our reserve-based credit facility and money market lines of credit that
are subject to a rate of interest that fluctuates based on short-term interest
rates. Because the majority of our long term obligations at December 31, 2000
were at fixed rates, we consider our interest rate exposure at such date to be
minimal. At December 31, 2000, we had no open interest rate hedge positions to
reduce our exposure to changes in interest rates.
FOREIGN CURRENCY EXCHANGE RATES
Our cash flow from certain international operations is based on the U.S.
dollar equivalent of cash flows measured in foreign currencies. Our Australian
oil production is sold under U.S. dollar contracts. Disbursement transactions
denominated in Australian dollars are converted to U.S. dollar equivalents based
on the average of the Australian and U.S. dollar exchange rates for the period
reported. We consider our current risk exposure to exchange rate movements,
based on net cash flows, to be immaterial. We did not have any open derivative
contracts relating to foreign currencies at December 31, 2000.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
NEWFIELD EXPLORATION COMPANY
INDEX
CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Management Report on Financial Statements................... 35
Independent Accountants' Report............................. 36
Consolidated Balance Sheet as of the fiscal years ended
December 31, 2000 and 1999................................ 37
Consolidated Statement of Income for each of the three years
in the period ended December 31, 2000..................... 38
Consolidated Statement of Stockholders' Equity for each of
the three years in the period ended December 31, 2000..... 39
Consolidated Statement of Cash Flows for each of the three
years in the period ended December 31, 2000............... 40
Notes to Consolidated Financial Statements.................. 41
Supplementary Oil and Gas Disclosures....................... 63
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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 on
Form 10-K for the year ended December 31, 2000. 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. Newfield'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 that 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
Newfield'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 Newfield'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 report.
/s/ DAVID A. TRICE /s/ TERRY W. RATHERT
David A. Trice Terry W. Rathert
President and Vice President and
Chief Executive Officer Chief Financial Officer
Houston, Texas
March 20, 2001
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INDEPENDENT ACCOUNTANTS' REPORT
To the Stockholders and Board of Directors of Newfield Exploration Company:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, stockholders' equity and cash flows present
fairly, in all material respects, the financial position of Newfield Exploration
Company and its subsidiaries at December 31, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2000, in conformity with accounting principles generally
accepted in the United States of America. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the
Company changed its method of accounting for its crude oil inventories in
connection with its adoption of SEC Staff Accounting Bulletin 101, "Revenue
Recognition in Financial Statements" effective January 1, 2000.
/s/ PRICEWATERHOUSECOOPERS
Houston, Texas
March 20, 2001
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
-------------------------
2000 1999
------------ ----------
ASSETS
Current assets:
Cash and cash equivalents................................. $ 18,451 $ 41,841
Accounts receivable -- oil and gas........................ 147,643 67,744
Inventories............................................... 7,164 9,962
Other current assets...................................... 5,891 6,382
---------- ----------
Total current assets............................... 179,149 125,929
---------- ----------
Oil and gas properties (full cost method, of which $106,783
at December 31, 2000 and $77,732 at December 31, 1999 were
excluded from amortization)............................... 1,589,558 1,210,895
Less -- accumulated depreciation, depletion and
amortization.............................................. (756,243) (566,053)
---------- ----------
833,315 644,842
---------- ----------
Furniture, fixtures and equipment, net...................... 4,028 3,369
Other assets................................................ 6,758 7,421
---------- ----------
Total assets....................................... $1,023,250 $ 781,561
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................... $ 10,209 $ 7,035
Accrued liabilities....................................... 128,190 81,635
Advances from joint owners................................ 2,661 2,057
---------- ----------
Total current liabilities.......................... 141,060 90,727
---------- ----------
Other liabilities........................................... 6,030 10,586
Long-term debt.............................................. 133,711 124,679
Deferred taxes.............................................. 79,244 36,801
---------- ----------
Total long-term liabilities........................ 218,985 172,066
---------- ----------
Company-obligated, mandatorily redeemable, convertible
preferred securities of Newfield Financial Trust I........ 143,750 143,750
---------- ----------
Commitments and contingencies
Stockholders' equity:
Preferred stock ($0.01 par value, 5,000,000 shares
authorized; no shares issued)........................... -- --
Common stock ($0.01 par value, 100,000,000 shares
authorized; 42,607,301 and 41,734,884 shares issued and
outstanding at December 31, 2000 and December 31, 1999,
respectively)........................................... 426 417
Additional paid-in capital................................ 286,412 267,352
Unearned compensation..................................... (6,201) (3,685)
Accumulated other comprehensive loss -- foreign currency
translation adjustment.................................. (4,644) (179)
Retained earnings......................................... 243,462 111,113
---------- ----------
Total stockholders' equity......................... 519,455 375,018
---------- ----------
Total liabilities and stockholders' equity......... $1,023,250 $ 781,561
========== ==========
The accompanying notes to consolidated financial statements are an integral part
of this statement.
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Oil and gas revenues.................................. $ 526,642 $ 287,889 $ 199,474
----------- ----------- -----------
Operating expenses:
Lease operating..................................... 65,372 45,561 35,345
Production and other taxes.......................... 10,288 2,215 --
Transportation...................................... 5,984 5,922 3,789
Depreciation, depletion and amortization............ 191,182 152,644 123,147
Ceiling test writedown.............................. 503 -- 104,955
General and administrative (includes non-cash stock
compensation of $3,047, $1,999 and $2,222 for
2000, 1999 and 1998, respectively)............... 32,084 16,404 12,070
----------- ----------- -----------
Total operating expenses.................... 305,413 222,746 279,306
----------- ----------- -----------
Income (loss) from operations......................... 221,229 65,143 (79,832)
Other income (expenses):
Interest income..................................... 2,124 1,616 964
Interest expense, net............................... (9,320) (11,188) (9,508)
Dividends on convertible preferred securities of
Newfield Financial Trust I.......................... (9,344) (3,556) --
----------- ----------- -----------
(16,540) (13,128) (8,544)
----------- ----------- -----------
Income (loss) before income taxes..................... 204,689 52,015 (88,376)
Income tax provision (benefit):
Current............................................. 15,897 1,105 --
Deferred............................................ 54,083 17,706 (30,677)
----------- ----------- -----------
69,980 18,811 (30,677)
----------- ----------- -----------
Income (loss) before cumulative effect of change in
accounting principle................................ 134,709 33,204 (57,699)
Cumulative effect of change in accounting principle,
net of tax.......................................... (2,360) -- --
----------- ----------- -----------
Net income (loss)........................... $ 132,349 $ 33,204 $ (57,699)
=========== =========== ===========
Earnings (loss) per share:
Basic --
Income (loss) before cumulative effect of change in
accounting principle............................. $ 3.18 $ 0.81 $ (1.55)
Cumulative effect of change in accounting principle,
net of tax....................................... (0.05) -- --
----------- ----------- -----------
Net income (loss)........................... $ 3.13 $ 0.81 $ (1.55)
=========== =========== ===========
Diluted --
Income (loss) before cumulative effect of change in
accounting principle............................. $ 2.98 $ 0.79 $ (1.55)
Cumulative effect of change in accounting principle,
net of tax....................................... (0.05) -- --
----------- ----------- -----------
Net income (loss)........................... $ 2.93 $ 0.79 $ (1.55)
=========== =========== ===========
Weighted average number of shares outstanding for
basic earnings per share............................ 42,332,835 41,194,021 37,311,928
=========== =========== ===========
Weighted average number of shares outstanding for
diluted earnings per share.......................... 47,227,708 42,293,865 37,311,928
=========== =========== ===========
The accompanying notes to consolidated financial statements are an integral part
of this statement.
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NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE DATA)
ACCUMULATED
COMMON STOCK ADDITIONAL OTHER TOTAL
------------------- PAID-IN UNEARNED RETAINED COMPREHENSIVE STOCKHOLDERS'
SHARES AMOUNT CAPITAL COMPENSATION EARNINGS LOSS EQUITY
---------- ------ ---------- ------------ -------- ------------- -------------
BALANCE, DECEMBER 31, 1997...... 35,975,777 $360 $160,672 $(4,592) $135,608 $ -- $292,048
Issuance of common stock...... 4,341,620 43 85,472 85,515
Issuance of restricted stock,
less amortization of $583... 115,668 1 2,706 (2,124) 583
Cancellation of restricted
stock....................... (3,336) (70) 50 (20)
Amortization of stock
compensation................ 1,659 1,659
Tax benefit from exercise of
stock options............... 1,862 1,862
Net loss...................... (57,699) (57,699)
---------- ---- -------- ------- -------- ------- --------
BALANCE, DECEMBER 31, 1998...... 40,429,729 404 250,642 (5,007) 77,909 -- 323,948
Issuance of common stock...... 1,283,544 13 7,995 8,008
Issuance of restricted stock,
less amortization of $218... 37,211 1,048 (830) 218
Cancellation of restricted
stock....................... (15,600) (371) 312 (59)
Amortization of stock
compensation................ 1,840 1,840
Tax benefit from exercise of
stock options............... 8,038 8,038
Comprehensive Income:
Net income.................... 33,204 33,204
Foreign currency translation
adjustment, net of tax of
$96......................... (179) (179)
--------
Total comprehensive
income................ 33,025
---------- ---- -------- ------- -------- ------- --------
BALANCE, DECEMBER 31, 1999...... 41,734,884 417 267,352 (3,685) 111,113 (179) 375,018
Issuance of common stock...... 776,161 8 6,925 6,933
Issuance of restricted stock,
less amortization of $646... 96,256 1 5,562 (4,917) 646
Amortization of stock
compensation................ 2,401 2,401
Tax benefit from exercise of
stock options............... 6,573 6,573
Comprehensive Income:
Net income.................... 132,349 132,349
Foreign currency translation
adjustment, net of tax of
$2,404...................... (4,465) (4,465)
--------
Total comprehensive
income................ 127,884
---------- ---- -------- ------- -------- ------- --------
BALANCE, DECEMBER 31, 2000...... 42,607,301 $426 $286,412 $(6,201) $243,462 $(4,644) $519,455
========== ==== ======== ======= ======== ======= ========
The accompanying notes to consolidated financial statements are an integral part
of this statement.
39
43
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
--------- --------- ---------
Cash flows from operating activities:
Net income (loss)....................................... $ 132,349 $ 33,204 $ (57,699)
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization................ 191,182 152,644 123,147
Ceiling test writedown.................................. 503 -- 104,955
Deferred taxes.......................................... 54,083 17,706 (30,677)
Stock compensation...................................... 3,047 1,999 2,222
Cumulative effect of change in accounting principle..... 2,360 -- --
--------- --------- ---------
383,524 205,553 141,948
Changes in assets and liabilities:
(Increase) decrease in accounts receivable -- oil and
gas.................................................. (81,854) (23,382) 11,028
(Increase) decrease in inventories...................... (2,143) 775 --
(Increase) decrease in other current assets............. (1,442) (2,780) 344
(Increase) decrease in other assets..................... 663 (4,010) (130)
Increase (decrease) in accounts payable and accrued
liabilities.......................................... 21,405 12,020 (4,652)
Increase in advances from joint owners.................. 604 105 1,392
Decrease in other liabilities........................... (4,313) (3,378) (3,355)
--------- --------- ---------
Net cash provided by operating activities....... 316,444 184,903 146,575
--------- --------- ---------
Cash flows from investing activities:
Acquisition of Gulf Australia, net of cash acquired of
$12,064.............................................. -- (10,977) --
Additions to oil and gas properties..................... (353,856) (197,882) (317,831)
Additions to furniture, fixtures and equipment.......... (1,691) (1,958) (1,160)
--------- --------- ---------
Net cash used in investing activities........... (355,547) (210,817) (318,991)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings................................ 219,000 443,000 795,750
Repayments of borrowings................................ (210,000) (527,000) (716,750)
Proceeds from issuance of convertible preferred
securities........................................... -- 143,750 --
Proceeds from issuances of common stock, net............ 6,933 8,008 85,291
--------- --------- ---------
Net cash provided by financing activities....... 15,933 67,758 164,291
--------- --------- ---------
Effect of exchange rate changes on cash and cash
equivalents............................................. (220) (95) --
--------- --------- ---------
Increase (decrease) in cash and cash equivalents.......... (23,390) 41,749 (8,125)
Cash and cash equivalents, beginning of period............ 41,841 92 8,217
--------- --------- ---------
Cash and cash equivalents, end of period.................. $ 18,451 $ 41,841 $ 92
========= ========= =========
The accompanying notes to consolidated financial statements are an integral part
of this statement.
40
44
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization and Principles of Consolidation
These financial statements include the accounts of Newfield Exploration
Company, a Delaware corporation, and its subsidiaries (collectively, the
"Company"). All significant intercompany balances and transactions have been
eliminated. 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 and access to capital and on the quantities of oil and gas reserves that
may be economically produced.
Use of Estimates and Reclassifications
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). Actual results could differ from these estimates. The
Company's most significant financial estimates are based on remaining proved oil
and gas reserves. Certain reclassifications have been made to prior years
reported amounts in order to conform with the current year presentation. As a
result of the adoption of Emerging Issues Task Force (EITF) No. 00-10,
"Accounting for Shipping and Handling Fees and Costs," the Company has
reclassified to operating expenses, for all periods presented, third party costs
incurred to transport production to the Company's respective sales point instead
of as a reduction of the related revenues as previously reported.
Accounting Change
The Company adopted SEC Staff Accounting Bulletin (SAB) No. 101, "Revenue
Recognition in Financial Statements," effective January 1, 2000. The adoption of
SAB No. 101 requires the Company to report crude oil inventory associated with
its Australian offshore operations at lower of cost or market, which is a change
from the historical policy of recording such inventory at market value on the
balance sheet date, net of estimated costs to sell. The cumulative effect of the
change from the acquisition date of the Company's Australian operations in July
1999 through December 31, 1999 is a reduction in net income of $2.36 million, or
$0.05 per diluted share, and is shown as the cumulative effect of change in
accounting principle on the consolidated statement of income for the year ended
December 31, 2000. The pro forma effect had SAB No. 101 been applied
retroactively in 1999 would have been as follows:
AS REPORTED PRO FORMA
----------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
Net income........................................... $33,204 $30,844
Earnings per share:
Basic.............................................. $ 0.81 $ 0.75
Diluted............................................ $ 0.79 $ 0.73
SAB No. 101 would not have effected periods prior to the acquisition of the
Company's Australian operations in July 1999.
41
45
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenue Recognition
Revenues are recorded when title passes to the customer. Revenues from the
production of oil and gas properties in which the Company has an interest with
other companies are recorded on the basis of sales to customers. Differences
between these sales and the Company's share of production are not significant.
Inventories
Inventories consist of international oil produced but not sold. Crude oil
from the Company's operations located offshore Australia is produced into a
floating production, storage and off-loading vessel (FPSO) and sold periodically
as a barge quantity is accumulated. The product inventory at December 31, 2000
consisted of approximately 252,450 barrels of crude oil, valued at $3.3 million
net to the Company's interest, and is carried at lower of average cost or
market. Also included in inventories are materials and supplies, stated at lower
of average cost or market.
Foreign Currency
The functional currency for all foreign operations, except Australia, is
the U.S. dollar. Translation adjustments resulting from translating the
Australian subsidiary's Australian dollar financial statements into U.S. dollars
are included as other comprehensive income in the consolidated statement of
stockholders' equity. Gains and losses incurred on currency transactions in
other than a country's functional currency are included in the consolidated
statement of income.
Earnings Per Share
Basic earnings (loss) per common share (EPS) is computed by dividing net
income (loss) by the weighted average number of common shares outstanding for
the period. Diluted EPS reflects the potential dilution that could occur if
outstanding stock options and convertible securities were exercised for or
converted into common stock.
42
46
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a calculation of basic and diluted weighted average shares
outstanding for each of the three years in the period ended December 31, 2000:
2000 1999 1998
-------------- -------------- --------------
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)
Income (loss) (numerator):
Income (loss) before cumulative effect
change in accounting principle........... $ 134,709 $ 33,204 $ (57,699)
Cumulative effect change in accounting
principle, net of tax.................... (2,360) -- --
----------- ----------- -----------
Income (loss) -- basic...................... 132,349 33,204 (57,699)
After tax dividends on convertible trust
preferred securities..................... 6,074 -- --
----------- ----------- -----------
Income (loss) -- diluted.................... $ 138,423 $ 33,204 $ (57,699)
=========== =========== ===========
Shares (denominator):
Shares -- basic............................. 42,332,835 41,194,021 37,311,928
Dilution effect of stock options outstanding
at end of period......................... 971,648 1,099,844 --
Dilution effect of convertible trust
preferred securities..................... 3,923,225 -- --
----------- ----------- -----------
Shares -- diluted........................... 47,227,708 42,293,865 37,311,928
=========== =========== ===========
Earnings (loss) per share:
Basic before change in accounting
principle................................ $ 3.18 $ 0.81 $ (1.55)
Basic....................................... $ 3.13 $ 0.81 $ (1.55)
Diluted before change in accounting
principle................................ $ 2.98 $ 0.79 $ (1.55)
Diluted..................................... $ 2.93 $ 0.79 $ (1.55)
The calculation of diluted EPS for 1999 does not include the effect of
3,923,225 shares underlying the 6.5% quarterly income convertible trust
preferred securities because to do so would have been antidilutive.
Additionally, the calculation of shares outstanding for diluted EPS for each of
the three years in the period ended December 31, 2000 does not include the
effect of outstanding stock options to purchase 127,000, 270,000 and 3,921,420
shares, respectively, because to do so would have been antidilutive.
Financial Instruments
Cash equivalents include highly-liquid investments with a maturity of three
months or less when acquired. The Company invests cash in excess of operating
requirements in U.S. Treasury Notes, Eurodollar bonds and investment grade
commercial paper. Cash equivalents are stated at cost, which approximates fair
market value.
The Company includes fair value information in the notes to financial
statements when the fair value of its financial instruments is different from
the book value. The book value of those financial instruments that are
classified as current assets or liabilities approximate fair value because of
the short maturity of those instruments.
The Company enters into various commodity price hedging contracts with
respect to its oil and gas production. While the use of these hedging
arrangements limits the downside risk of adverse price movements, they may also
limit future revenues from favorable price movements. The use of hedging
transactions also involves the risk that the counterparties will be unable to
meet the financial terms of such
43
47
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
transactions. Such contracts are accounted for as hedges, in accordance with
SFAS No. 80. Gains and losses on these contracts are recognized in revenue in
the period in which the underlying production is delivered. These instruments
are measured for correlation at both the inception of the contract and on an
ongoing basis. If these instruments cease to meet the criteria for deferral
accounting, any subsequent gains or losses are recognized in revenue. If these
instruments are terminated prior to maturity, resulting gains and losses
continue to be deferred until the hedged item is recognized in revenue. Neither
the hedging contracts nor the unrealized gains or losses on these contracts are
recognized in the financial statements.
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires
enterprises to recognize all derivatives as either assets or liabilities on
their balance sheet and measure those instruments at fair value. See Note
3 -- "Recent Adoption of SFAS No. 133."
Oil and Gas Properties
The Company uses the full cost method of accounting. Under this method, all
costs incurred in the acquisition, exploration and development of oil and gas
properties are capitalized into cost centers that are established on a
country-by-country basis. Such capitalized costs and estimated future
development and dismantlement costs are amortized on a unit-of-production method
based on proved reserves. For each cost center, the net capitalized costs of oil
and gas properties are limited to the lower of unamortized cost or the cost
center ceiling, defined as the sum of the present value (10% per annum 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. In
accordance with full cost accounting rules, the Company recorded a charge of
$0.5 million in 2000 related to abandoned prospect costs in foreign locations
other than Australia or China. Additionally, a writedown of domestic oil and gas
properties of $105.0 million (resulting in a charge to earnings of $68.3 million
after-tax) was recorded at December 31, 1998. The writedown was primarily
attributable to the lower prices for both oil and natural gas at December 31,
1998.
Proceeds from the sale of oil and gas properties are applied to reduce the
costs in the cost center unless the sale involves a significant quantity of
reserves in relation to the cost center, in which case a gain or loss is
recognized.
Unevaluated properties and associated costs relating to domestic and
Australian operations not currently being amortized and included in oil and gas
properties were $90.5 million and $67.3 million at December 31, 2000 and 1999,
respectively. The properties associated with these costs were at such dates
undergoing exploration activities or are properties on which the Company intends
to commence such activities in the future. The Company believes that these
unevaluated properties at December 31, 2000 will be substantially evaluated and
therefore subject to amortization within 12 to 24 months. Additionally, at
December 31, 2000 and 1999, there were $16.2 million and $10.4 million,
respectively, of unproved property costs associated with the Company's
investment in international activities other than in Australia. While the
Company will continue to evaluate these properties and costs, the timing of the
completion of such evaluations is uncertain because of the substantial time
period required to establish the commerciality of projects or commence
operations in some foreign countries.
Other property and equipment are recorded at cost and are depreciated over
their estimated useful lives of five to seven years using the straight-line
method. At December 31, 2000 and 1999, furniture, fixtures and equipment is net
of accumulated depreciation of $3.5 million and $2.6 million, respectively.
44
48
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Abandonment and Dismantlement Costs
Future abandonment and dismantlement costs include costs to dismantle and
relocate or dispose of the Company's offshore production platforms, FPSOs,
gathering systems, wells and related structures. The Company develops estimates
of its future abandonment and dismantlement costs for each of its offshore
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 at least annually by the Company's
engineers.
Total estimated future abandonment and dismantlement costs associated with
the Company's developed and acquired properties were $120.4 million, $133.1
million and $69.1 million as of December 31, 2000, 1999 and 1998, 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 $56.9 million,
$43.1 million and $29.7 million as of December 31, 2000, 1999 and 1998,
respectively.
Income Taxes
The Company uses the liability method of accounting for income taxes. Under
this method, deferred tax assets and liabilities are determined by applying tax
regulations existing at the end of a reporting period to the cumulative
temporary differences between the tax bases of assets and liabilities and their
reported amounts in the financial statements.
A valuation allowance is established to reduce deferred tax assets if it is
more likely than not that the related tax benefits will not be realized.
Concentration of Credit Risk
The Company maintains cash balances with several banks that frequently
exceed federally insured limits and invests its cash in investment grade
commercial and U.S. Government-backed securities. The Company's joint interest
partners consist primarily of independent oil and gas producers. The Company's
oil and gas production purchasers consist primarily of independent marketers and
major gas pipeline companies. The Company performs credit evaluations of its
customers' financial condition and obtains letters of credit and parental
guarantees from selected customers. The Company has not experienced any
significant losses from uncollectible accounts. All of the Company's hedging
transactions have been carried out in the over-the-counter market.
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, 2000 to Conoco Inc. (35%)
and Superior Natural Gas Corporation (16%); for the year ended December 31, 1999
to Conoco Inc. (18%) and Superior Natural Gas Corporation (10%); and for the
year ended December 31, 1998 to Conoco Inc. (13%) and Coast Energy Group (10%).
Because alternative purchasers of oil and gas are readily available, the Company
believes that the loss of any of these purchasers would not have a material
adverse effect on the Company.
2. HEDGING TRANSACTIONS:
During 2000, approximately 47% of the Company's equivalent production was
subject to hedge positions as compared to 55% in 1999 and 61% in 1998.
45
49
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 2000, the Company had entered into commodity price
hedging contracts with respect to its natural gas production for 2001 and 2002
as follows:
NYMEX CONTRACT PRICE PER MMBTU
--------------------------------------------------
COLLARS
VOLUME IN SWAPS -------------------------- FLOOR FAIR MARKET
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
----------------------------- --------- --------- ----------- ------------ --------- ---------------
January 2001 -- March 2001
Price Swap Contracts....... 10,510 $3.29 -- -- -- $ (64.5 Million)
Collar Contracts........... 5,980 -- $2.75-$7.00 $3.21-$10.80 -- $ (20.5 Million)
April 2001 -- June 2001
Price Swap Contracts....... 7,380 $3.42 -- -- -- $ (17.8 Million)
Collar Contracts........... 9,080 -- $2.75-$4.50 $3.21-$6.15 -- $ (9.3 Million)
July 2001 -- September 2001
Price Swap Contracts....... 2,780 $5.17 -- -- -- $ (0.5 Million)
Collar Contracts........... 9,400 -- $3.50-$4.50 $3.85-$6.00 -- $ (6.4 Million)
October 2001 -- December 2001
Price Swap Contracts....... 1,770 $5.23 -- -- -- $ (0.3 Million)
Collar Contracts........... 900 -- $4.00-$4.50 $5.75-$6.00 -- $ (0.3 Million)
Floor Contracts............ 900 -- -- -- $4.54 $ 0.2 Million
January 2002 -- December 2002
Collar Contracts........... 4,800 -- $4.00 $4.80-$5.15 -- $ (0.4 Million)
---------------
(1) Except for January 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at December
31, 2000. Because January 2001 NYMEX futures contracts expired on December
27, 2000, the fair market value of January 2001 hedging contracts represents
the actual settlement value of such contracts.
As of December 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its natural gas production for 2000 as
follows:
NYMEX CONTRACT PRICE PER MMBTU
-----------------------------------------
COLLARS
VOLUME IN SWAPS ----------------- FLOOR FAIR MARKET
PERIOD MMMBTUS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
---------------------------------- --------- --------- ------ -------- --------- ------------
January 2000
Price Swap Contracts............ 750 $2.74 -- -- -- $0.9 Million
Collar Contracts................ 250 -- $2.63 $ 3.25 -- $0.1 Million
Floor Contracts................. 100 -- -- -- $2.63 --
---------------
(1) Because January 2000 NYMEX futures contracts expired on December 28, 1999,
the fair market value of these hedging contracts represents the actual
settlement value of such contracts.
These hedging transactions are settled based upon the average of the
reported settlement prices on the NYMEX for the last three trading days or,
occasionally, the penultimate trading day of a particular contract month. With
respect to any particular swap transaction, the counterparty is required to make
a payment to the Company in the event that the settlement price for any
settlement period is less than the swap price for such transaction, and the
Company is required to make payment to the counterparty in the event that the
settlement price for any settlement period is greater than the swap price for
such transaction. For any particular collar transaction, the counterparty is
required to make a payment to the Company if the settlement price for any
settlement period is below the floor price for such transaction, and the Company
is required to make payment to the counterparty if the settlement price for any
settlement period is above the ceiling price of such transaction. For any
particular floor transaction, the counterparty
46
50
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
is required to make a payment to the Company if the settlement price for any
settlement period is below the floor price for such transaction. The Company is
not required to make any payment in connection with the settlement of a floor
transaction.
The Company believes that it has no material basis risk with respect to gas
swaps because substantially all of the Company's natural gas production is sold
under spot contracts that have historically correlated with the settlement
price.
As of December 31, 2000, the Company had entered into commodity price
hedging contracts with respect to its oil production for 2001 and 2002 as
follows:
NYMEX CONTRACT PRICE PER BBL
---------------------------------------------------------
COLLARS
VOLUME IN SWAPS ----------------------------- FLOOR FAIR MARKET
PERIOD BBLS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
----------------------------- --------- --------- ------------- ------------- ------------- -------------
January 2001 -- March 2001
Price Swap Contracts....... 540,000 $21.99 -- -- -- $(2.9 Million)
Collar Contracts........... 270,000 -- $25.00 $30.05-$30.75 -- $ 0.2 Million
Floor Contracts............ 238,500 -- -- -- $22.17-$29.58 $ 0.6 Million
April 2001 -- June 2001
Price Swap Contracts....... 436,800 $22.80 -- -- -- $(1.1 Million)
Collar Contracts........... 364,000 -- $25.00-$27.25 $30.05-$30.75 -- $ 0.6 Million
Floor Contracts............ 186,550 -- -- -- $22.17-$28.28 $ 0.5 Million
July 2001 -- September 2001
Price Swap Contracts....... 391,000 $23.88 -- -- -- $(0.3 Million)
Collar Contracts........... 414,000 -- $24.00-$26.25 $27.30-$32.45 -- $ 0.6 Million
Floor Contracts............ 207,000 -- -- -- $22.17-$27.04 $ 0.6 Million
October 2001 -- December 2001
Price Swap Contracts....... 386,400 $23.24 -- -- -- $(0.3 Million)
Collar Contracts........... 345,000 -- $24.00-$25.25 $27.30-$30.75 -- $ 0.3 Million
Floor Contracts............ 262,200 -- -- -- $22.17-$26.00 $ 0.9 Million
January 2002 -- March 2002
Collar Contracts........... 517,500 -- $22.00-$25.00 $25.75-$30.75 -- $ 0.2 Million
April 2002 -- June 2002
Collar Contracts........... 455,000 -- $22.00-$25.00 $25.75-$30.75 -- $ 0.1 Million
July 2002 -- September 2002
Collar Contracts........... 345,000 -- $23.00-$25.00 $26.75-$30.75 -- $ 0.3 Million
October 2002 -- December 2002
Collar Contracts........... 184,000 -- $25.00 $28.00-$30.75 -- $ 0.2 Million
---------------
(1) Except for January 2001 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at December
31, 2000. Because January 2001 NYMEX futures contracts expired on December
19, 2000, the fair market value of January 2001 hedging contracts represents
the actual settlement value of such contracts.
47
51
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1999, the Company had entered into commodity price
hedging contracts with respect to its oil production for 1999 as follows:
NYMEX CONTRACT PRICE PER BBL
---------------------------------------------------------
COLLARS
VOLUME IN SWAPS ----------------------------- FLOOR FAIR MARKET
PERIOD BBLS (AVERAGE) FLOORS CEILINGS CONTRACTS VALUE(1)
----------------------------- --------- --------- ------------- ------------- ------------- -------------
January 2000-March 2000
Price Swap Contracts....... 455,000 $21.63 -- -- -- $(1.6 Million)
Collar Contracts........... 182,000 -- $18.28-$19.50 $20.10-$21.00 -- $(0.2 Million)
Floor Contracts............ 91,000 -- -- -- $19.32 $(0.8 Million)
April 2000-June 2000
Price Swap Contracts....... 455,000 $21.70 -- -- -- $(0.3 Million)
Collar Contracts........... 182,000 -- $18.28-$19.50 $20.10-$21.00 -- $(0.3 Million)
July 2000-September 2000
Price Swap Contracts....... 460,000 $21.70 -- -- -- $ 0.3 Million
Collar Contracts........... 92,000 -- $18.28 $21.00 -- $(0.1 Million)
October 2000-December 2000
Price Swap Contracts....... 460,000 $21.70 -- -- -- $ 0.7 Million
January 2001-March 2001
Price Swap Contracts....... 180,000 $21.25 -- -- -- $ 0.3 Million
---------------
(1) Except for January 2000 hedging contracts, fair market value is calculated
using prices derived from NYMEX futures contract prices existing at December
31, 1999. Because January 2000 NYMEX futures contracts expired on December
20, 1999, the fair market value of January 2000 hedging contracts represents
the actual settlement value of such contracts.
Because substantially all of the Company's domestic oil production is sold
under spot contracts that have historically correlated to the NYMEX West Texas
Intermediate price, the Company believes that it has no material basis risk with
respect to these transactions. The actual cash price the Company receives in the
U.S., however, generally is about $2.00 per barrel less than the NYMEX West
Texas Intermediate price when adjusted for location and quality differences.
See Note 3 -- "Recent Adoption of SFAS No. 133" for a discussion of the
Company's adoption of SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities."
3. RECENT ADOPTION OF SFAS NO. 133:
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." The
FASB has subsequently issued SFAS Nos. 137 and 138, which are amendments to SFAS
No. 133. SFAS No. 133 is effective for fiscal years beginning after June 30,
2000. We adopted SFAS No. 133 on January 1, 2001.
SFAS No. 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. All derivatives will be recorded on the
balance sheet at fair value and changes in the fair value of derivatives are
recorded each period in current earnings or other comprehensive income,
depending on whether a derivative is designated as part of a hedge transaction
and, if it is, depending on the type of transaction. The Company's derivative
contracts consist primarily of cash flow hedge transactions in which it hedges
the variability of cash flows related to a forecasted transaction. Changes in
the fair value of these derivative instruments will be recorded in other
comprehensive income and will be reclassified as earnings in the periods in
which earnings are impacted by the variability of the cash flows of the hedged
item. The ineffective portion related to basis changes and time value of all
hedges will be recognized in current period earnings.
48
52
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In accordance with the transition provisions of SFAS No. 133, on January 1,
2001, in connection with its hedging activities, the Company recorded as
cumulative effect adjustments a loss of $74.2 million (net of tax of $40.0
million) in accumulated other comprehensive loss and a loss of $4.8 million (net
of tax of $2.6 million) in 2001 earnings. In addition, the adoption resulted in
the recognition of $17.7 million of derivative assets and $139.3 million of
derivative liabilities on the balance sheet on January 1, 2001. Based on fair
values at January 1, 2001 and the settlement dates of such derivatives, the
Company expects to reclassify approximately $75.3 million (net of tax of $40.5
million) of the transition adjustment recorded in accumulated other
comprehensive loss to earnings in 2001.
The Company is not in violation of any debt covenants or other contracts as
a result of implementing SFAS No. 133.
4. DEBT:
Long-term debt consisted of the following:
DECEMBER 31, DECEMBER 31,
2000 1999
------------ ------------
(IN THOUSANDS)
Senior Unsecured Debt:
Bank revolving credit facility:
Prime rate based loans................................. $ -- $ --
LIBOR based loans...................................... 4,000 --
-------- --------
Total bank revolving credit facility.............. 4,000 --
-------- --------
7.45% Senior Notes due 2007............................... 124,711 124,679
-------- --------
Money market credit lines................................. 5,000 --
-------- --------
Long-term debt.................................... $133,711 $124,679
======== ========
At December 31, 2000, the interest rate was 7.22% for LIBOR based loans and
for the loans outstanding under the money market credit lines was 7.31%.
The estimated fair market value of the 7.45% Senior Notes due 2007, based
on quoted market prices at December 31, 2000 and 1999, was $114.0 million and
$115.2 million, respectively. Debt outstanding under the bank revolving credit
facility is stated at cost, which approximates fair market value.
At December 31, 2000, the Company maintained its reserve-based revolving
credit facility with Chase Bank of Texas, National Association, as agent. As
discussed in Note 14 -- "Subsequent Events," the Company obtained a new
reserved-based revolving credit facility as of January 23, 2001. The old
facility provided a $225 million revolving credit maturing on October 31, 2002.
The amount available under the facility was subject to a calculated borrowing
base determined by a majority of the banks participating in the facility, which
was reduced by the aggregate principal outstanding on the Company's senior notes
($125 million at December 31, 2000). The borrowing base was $380 million at
December 31, 2000. At December 31, 2000, there was $4 million outstanding under
the facility.
Borrowings under the old facility bore interest, at the Company's option,
at (i) the higher of (a) the federal fund rate plus 50 basis points and (b) the
bank's prime rate or (ii) LIBOR plus a variable margin, which was based upon the
loan amount outstanding relative to the borrowing base and the Company's
corporate credit ratings.
The facility also provided for the payment of a commitment fee and a
standby fee. The Company paid fees of approximately $315,000, $336,000 and
$178,000 for the years ended December 31, 2000, 1999 and 1998, respectively.
49
53
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. CONVERTIBLE PREFERRED SECURITIES OF NEWFIELD FINANCIAL TRUST I:
In August 1999, Newfield Financial Trust I, a Delaware business trust and
wholly owned subsidiary of the Company (the "Trust"), issued, in an underwritten
public offering, $143,750,000 (2,875,000 securities having a liquidation
preference of $50 each) of 6.5% Cumulative Quarterly Income Convertible
Securities, Series A (the "Trust Preferred Securities"). The proceeds of the
issuance of the Trust Preferred Securities were used to purchase $143,750,000 of
the Company's 6.5% Junior Subordinated Convertible Debentures, due 2029 (the
"Debentures"). The interest terms and payment dates of the Debentures correspond
to those of the Trust Preferred Securities. The Company's obligations under the
Debentures and related agreements, when taken together, constitute a full and
unconditional guarantee of payments due on the Trust Preferred Securities. The
sole asset of the Trust is the Debentures. The Trust has no independent
operations. The Debentures are eliminated in the consolidated financial
statements.
The Trust Preferred Securities accrue and pay distributions quarterly in
arrears at a rate of 6.5% per annum on the stated liquidation amount of $50 per
Trust Preferred Security on February 15, May 15, August 15, and November 15 of
each year to holders of record 15 business days immediately preceding the
distribution payment date. The Company may on one or more occasions defer the
payment of interest on the Debentures for up to 20 consecutive quarterly periods
unless an event of default on the Debentures has occurred and is continuing.
During any such deferral period, the Trust will defer the payment of
distributions, but accrued distributions on the Trust Preferred Securities will
compound quarterly and the Company will generally not be permitted to declare or
pay any dividends or distributions on, or redeem or acquire, any of its capital
stock or make any payment of principal or interest on any debt securities that
rank equal or junior to the Debentures.
The Trust Preferred Securities are convertible at the option of the holder
at any time into common stock of the Company at the rate of 1.3646 shares of
Company common stock per Trust Preferred Security. This conversion rate is
subject to adjustment to prevent dilution and is currently equivalent to a
conversion price of $36.64 per share of Company common stock. The Trust
Preferred Securities are mandatorily redeemable upon maturity of the Debentures
on August 15, 2029, and on a proportionate basis to the extent of any earlier
redemption of any Debenture by the Company. The Debentures are redeemable by the
Company at any time after August 15, 2002.
The estimated fair market value of the Trust Preferred Securities at
December 31, 2000 and 1999, based on quoted market prices, was $207.0 million
and $134.8 million, respectively.
6. INCOME TAXES:
Income (loss) before income taxes is composed of the following:
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
2000 1999 1998
--------- -------- ---------
(IN THOUSANDS)
U.S. federal.......................................... $180,741 $41,178 $(88,376)
Foreign............................................... 23,948 10,837 --
-------- ------- --------
Total....................................... $204,689 $52,015 $(88,376)
======== ======= ========
50
54
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The total provision for income taxes consists of the following:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2000 1999 1998
-------- -------- ---------
(IN THOUSANDS)
Current taxes:
U.S. federal......................................... $15,897 $ 1,105 $ --
Deferred taxes:
U.S. federal......................................... 47,442 13,668 (30,677)
Foreign.............................................. 6,641 4,038 --
------- ------- --------
$69,980 $18,811 $(30,677)
======= ======= ========
The components of deferred tax assets and liabilities are as follows:
DECEMBER 31, 2000 DECEMBER 31, 1999
-------------------- --------------------
U.S. AUSTRALIA U.S. AUSTRALIA
-------- --------- -------- ---------
(IN THOUSANDS)
Deferred tax assets:
Alternative minimum tax credit............. $ -- $ -- $ 2,953 $ --
Net operating loss carry forwards.......... 1,750 190 23,961 4,646
Other, net................................. 2,609 284 1,834 --
-------- ------- -------- -------
Gross deferred tax asset........... 4,359 474 28,748 4,646
Valuation allowance........................ -- -- -- (2,326)
-------- ------- -------- -------
Net deferred tax asset............. 4,359 474 28,748 2,320
-------- ------- -------- -------
Deferred tax liability:
Oil and gas properties..................... (82,175) (1,902) (65,549) --
-------- ------- -------- -------
Net deferred tax asset (liability)........... (77,816) (1,902) (36,801) 2,320
Less current deferred tax asset.............. -- -- -- 2,320
-------- ------- -------- -------
Noncurrent deferred tax liability............ $(77,816) $(1,428) $(36,801) $ --
======== ======= ======== =======
U.S. deferred taxes have not been provided on foreign income of $32.1
million that is permanently reinvested in Australia. The Company currently does
not have any foreign tax credits available to reduce U.S. taxes on such income
if it was repatriated.
In connection with its acquisition of Gulf Australia in July 1999, the
Company recorded a valuation allowance of $2.3 million to reduce acquired NOL
carryforwards to an amount that, more likely than not, would be realized. During
2000, primarily as a result of a substantial increase in estimated taxable
income resulting from increased commodity prices, the valuation allowance was
reversed and a majority of the remaining Australian NOL carryforwards were
realized.
51
55
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. COMMITMENTS AND CONTINGENCIES:
The Company has entered into a non-cancellable operating lease agreement
for office space in Houston, Texas. The lease term expires in October 2005,
subject to two options to renew for five years each. In addition, the Company
enters into various other equipment leases as part of its operations.
Future minimum lease payments required as of December 31, 2000 related to
these operating leases are as follows:
YEAR ENDING DECEMBER 31,
------------------------ (IN THOUSANDS)
2001................................................... $ 3,279
2002................................................... 3,360
2003................................................... 2,320
2004................................................... 1,762
2005................................................... 1,525
-------
Total minimum lease payments................. $12,246
=======
Rent expense for the years ended December 31, 2000, 1999 and 1998 was $3.2
million, $2.8 million and $1.9 million, 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 that these matters will
have a material adverse effect on the financial position, cash flows or results
of operations of the Company.
52
56
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. STOCK-BASED COMPENSATION:
The Company has several stock-based compensation plans, each of which is
described below. The Company applies APB Opinion No. 25 and related
interpretations in accounting for its stock-based compensation plans.
Stock Option Plans
The Company has granted options pursuant to its 1989, 1990, 1991, 1993,
1995, 1998 and 2000 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.
The following is a summary of all stock option activity for 1998, 1999 and
2000:
NUMBER OF WEIGHTED
SHARES AVERAGE
UNDERLYING EXERCISE
OPTIONS PRICE
---------- --------
Outstanding at December 31, 1997............................ 3,391,990 $ 7.84
Granted................................................... 959,900 20.81
Exercised................................................. (296,570) 5.13
Forfeited................................................. (133,900) 21.22
---------- ------
Outstanding at December 31, 1998............................ 3,921,420 10.76
Granted................................................... 308,000 27.38
Exercised................................................. (1,243,960) 5.80
Forfeited................................................. (83,800) 18.68
---------- ------
Outstanding at December 31, 1999............................ 2,901,660 14.43
Granted................................................... 827,000 31.74
Exercised................................................. (738,170) 8.14
Forfeited................................................. (70,330) 25.01
---------- ------
Outstanding at December 31, 2000............................ 2,920,160 $20.67
========== ======
Exercisable at December 31, 1998............................ 2,442,030 $ 5.52
========== ======
Exercisable at December 31, 1999............................ 1,534,420 $ 8.16
========== ======
Exercisable at December 31, 2000............................ 1,106,550 $11.81
========== ======
At December 31, 2000, the Company had an additional 1,680,464 options
available for grant. If granted, these additional options will be exercisable at
a price not less than the fair market value per share of the Company's common
stock on the date of grant. The weighted average fair value of options granted
during 2000, 1999 and 1998 was $15.41, $12.68 and $8.92, respectively.
The fair value of each stock option granted is estimated as of the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions for grants in 2000, 1999 and 1998: no dividend yield for all
years; expected volatility of 34.78%, 33.77% and 30.57%, respectively; risk-free
interest rates of 6.76%, 5.97% and 5.55%, respectively; and an expected option
life of 6.50 years for all years.
53
57
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information about stock options outstanding
and exercisable at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------------------------- ----------------------------
WEIGHTED AVERAGE WEIGHTED WEIGHTED
RANGE OF REMAINING AVERAGE AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
$ 3.50 to $ 5.62 552,450 2.0 years $ 3.88 552,450 $ 3.88
10.94 to 14.78 254,460 5.0 years 13.87 195,140 13.85
15.04 to 20.94 426,800 7.3 years 17.12 64,100 18.82
21.06 to 46.38 1,686,450 8.3 years 28.09 294,860 23.78
---------------- --------- --------- ------ --------- ------
$ 3.50 to $46.38 2,920,160 6.7 years $20.67 1,106,550 $11.81
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 2000, 1999
and 1998 resulted in a deferred tax benefit to the Company of approximately $6.6
million, $8.0 million and $1.9 million, respectively.
Employee Stock Purchase Plan
Pursuant to the Company's employee stock purchase plan, for each six month
period beginning on January 1 or July 1 during the term of the plan, each
eligible employee has the opportunity to purchase common stock for a purchase
price equal to 85% of the lesser of the fair market value of the common stock on
(i) the first day of the period or (ii) the last day of the period. No employee
may purchase common stock under the plan valued at more than $25,000 in any
calendar year.
At December 31, 2000, 200,000 shares of common stock were available for
issuance pursuant to the stock purchase plan. Under the plan, the Company has
sold 22,180 shares, 24,945 shares and 25,369 shares to employees in 2000, 1999
and 1998, respectively, which had weighted average prices of $26.75, $19.73 and
$18.72, respectively. In accordance with APB Opinion No. 25 and related
interpretations, the Company has not recognized any compensation expense with
respect to the plan.
The weighted average fair value of the option to purchase stock during
2000, 1999 and 1998 was $8.87, $6.34 and $5.92, respectively. The fair value of
each option granted under the stock purchase plan is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions for grants in 2000, 1999 and 1998: no dividend yield for all
years; expected volatility of 37.86%, 33.77% and 30.57%, respectively; risk-free
interest rates of 5.73%, 4.78% and 5.01%, respectively; and an expected option
life of six months for all years.
54
58
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro Forma Net Income and Net Income Per Common Share
If the fair value based method of accounting in SFAS No. 123, "Accounting
for Stock-Based Compensation" had been applied, the Company's net income and
earnings per common share for 2000, 1999 and 1998 would have approximated the
pro forma amounts below:
YEAR ENDED DECEMBER 31,
--------------------------------------
2000 1999 1998
----------- ---------- -----------
(IN THOUSANDS EXCEPT PER SHARE DATA)
Net income (loss):
As reported........................................ $132,349 $33,204 $(57,699)
Pro forma.......................................... 128,702 31,242 (59,275)
Basic earnings (loss) per common share --
As reported........................................ $ 3.13 $ 0.81 $ (1.55)
Pro forma.......................................... 3.04 0.76 (1.59)
Diluted earnings (loss) per common share --
As reported........................................ $ 2.93 $ 0.79 $ (1.55)
Pro forma.......................................... 2.85 0.74 (1.59)
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. The Company anticipates making awards in the
future under its stock-based compensation plans.
Restricted Stock
The Company has adopted four plans pursuant to which restricted shares of
common stock may be granted.
Under the Newfield Exploration Company 1995 Omnibus Stock Plan (the "1995
Omnibus Plan"), the Company may grant to employees (including an officer or a
director who is also an employee) as restricted common stock all or a portion of
400,000 shares of common stock reserved under the 1995 Omnibus Plan. In 1999 and
1998 the Company issued 29,000 and 107,100 shares, respectively, of restricted
common stock that fully vest after nine years. Vesting may, however, be
accelerated if certain performance-based criteria are met.
Under the Newfield Exploration Company 2000 Non-Employee Director
Restricted Stock Plan (the "Non-Employee Director Plan"), subject to a maximum
of 50,000 shares, each non-employee director who is in office immediately after
each annual meeting of stockholders of the Company shall, unless electing to not
participate, receive a number of restricted shares determined by dividing
$30,000 by the fair market value on the date of the annual meeting of
stockholders, subject to the terms of the plan. The forfeiture restrictions with
respect to all restricted shares granted since the last annual meeting of
stockholders lapse on the day before the first annual meeting of stockholders
following the date of issuance of such shares, provided that the holder remains
a director until such time. The Company issued 5,250 shares to seven
non-employee directors in 2000 pursuant the Non-Employee Director Plan. The
Company issued 8,211 shares to seven non-employee directors in 1999 and 8,568
shares to seven non-employee directors in 1998 pursuant to a predecessor plan
with terms substantially similar to the current plan.
Under the Newfield Exploration Company 1998 Omnibus Stock Plan (the "1998
Omnibus Plan"), the Company may, subject to certain restrictions, grant to
employees (including an officer or director who is also an employee) as
restricted common stock all or a portion of 250,000 shares of common stock
reserved under the 1998 Omnibus Plan. In 2000 the Company issued 91,006 shares
of restricted stock that fully vest after nine years. Vesting may, however, be
accelerated if certain performance-based criteria are met.
55
59
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Under the Newfield Exploration Company 2000 Omnibus Stock Plan (the "2000
Omnibus Plan"), the Company may, subject to certain restrictions, grant to
employees (including an officer or director who is also an employee) as
restricted common stock all or a portion of 200,000 shares of common stock
reserved under the 2000 Omnibus Plan.
In accordance with APB Opinion No. 25, the Company recognized unearned
compensation for the fair value of the restricted common stock in the amount of
$2.9 million for 2000, $1.0 million for 1999 and $2.7 million for 1998. This
amount is charged to stockholders' equity and recognized as compensation expense
over the applicable vesting period, in the amount of $1.8 million for 2000, $0.9
million for 1999 and $2.0 million for 1998. The weighted average price for
96,256 shares of restricted common stock issued in 2000 is $30.37. The weighted
average price for 37,211 shares of restricted common stock issued in 1999 is
$27.75. The weighted average price for 115,668 shares of restricted common stock
issued in 1998 is $23.40.
9. 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 other than employees of the Company's Australian subsidiaries. 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 $714,000, $605,000 and $546,000 for the years ended December
31, 2000, 1999 and 1998, respectively.
The Company also sponsors the Newfield Employee 1993 Incentive Compensation
Plan (the "Incentive 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 Incentive 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 Incentive
Plan. The Incentive Plan is administered by the Compensation Committee of the
Board of Directors with award amounts recommended by the Chief Executive Officer
of the Company, based on the performance of the Company and the eligible
employees during the performance period. All employees of the Company are
eligible for awards if employed on both October 1 and December 31 of the
performance period. Awards may have both a current and a deferred component of
compensation. Eligible employees may elect for deferred amounts to be paid in
common stock instead of cash. If the eligible employee elects for a deferred
amount to be paid in common stock, the number of shares of common stock to be
awarded is determined by using the fair market value of common stock on the date
of the award. Total expense under the Incentive Plan for the years ended
December 31, 2000, 1999 and 1998 were $12.8 million, $3.9 million and $1.9
million, respectively.
During 1997, the Company implemented a highly compensated employee Deferred
Compensation Plan (the "Deferred Plan"). This non-qualified plan allows an
eligible employee to defer a portion of the employee's salary or bonus on an
annual basis. The Company matches $1.00 for each $1.00 of employee deferral,
with the Company's contribution not to exceed 8% of an employee's salary,
subject to limitations imposed by the Deferred Plan. The Company's contribution
is reduced by the amount of contribution made by the Company to the 401(k) Plan
for each participant. The Company's contributions to the Deferred Plan totaled
$29,000, $34,000 and $30,000 for the years ended December 31, 2000, 1999 and
1998, respectively.
56
60
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. STOCKHOLDER RIGHTS PLAN:
In 1999, the Company adopted a stockholder rights plan. The plan is
designed to ensure that all stockholders of the Company receive fair and equal
treatment in the event of a proposed takeover of the Company. It includes
safeguards against partial or two-tiered tender offers, squeeze-out mergers and
other abusive takeover tactics.
The plan provides for the issuance of one right for each outstanding share
of the Company's common stock. The rights will become exercisable only if a
person or group acquires 20% or more of the Company's outstanding voting stock
or announces a tender or exchange offer that would result in ownership of 20% or
more of the Company's voting stock.
Each right will entitle the holder to buy one one-thousandth (1/1000) of a
share of a new series of junior participating preferred stock at an exercise
price of $85 per right, subject to antidilution adjustments. Each one
one-thousandth of a share of this new preferred stock has the dividend and
voting rights of, and is designed to be substantially equivalent to, one share
of common stock. The Company's Board of Directors may, at its option, redeem all
rights for $0.01 per right at any time prior to the acquisition of 20% or more
of the Company's stock by a person or group.
If a person or group acquires 20% or more of the Company's outstanding
voting stock, each right will entitle holders, other than the acquiring party,
to purchase common stock of the Company having a market value of $170 for a
purchase price of $85, subject to antidilution adjustments.
The plan also includes an exchange option. If a person or group acquires
20% or more, but less than 50% of the outstanding voting stock, the Board of
Directors may at its option exchange the rights in whole or part for shares of
common stock of the Company. Under this option, the Company would issue one
share of common stock, or one one-thousandth of a share of new preferred stock,
for each two shares of common stock for which a right is then exercisable. This
exchange would not apply to rights held by the person or group holding 20% or
more of the Company's voting stock.
If, after the rights have become exercisable, the Company merges or
otherwise combines with another entity, or sells assets constituting more than
50% of its assets or producing more than 50% of its earning power or cash flow,
each right then outstanding will entitle its holder to purchase for $85, subject
to antidilution adjustments, a number of the acquiring party's common shares
having a market value of twice that amount.
This plan will not prevent, nor is it intended to prevent, a takeover of
the Company. Since the rights may be redeemed by the Board under certain
circumstances, they should not interfere with any merger or other business
combination approved by the Board. The issuance of the rights does not in any
way diminish the financial strength of the Company or interfere with its
business plans. The issuance of the rights has no dilutive effect, does not
affect reported earnings per share or change the way the common stock of the
Company is currently traded.
57
61
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. PROPERTY ACQUISITIONS:
In February 2000, the Company acquired interests in three producing gas
fields in South Texas for approximately $139 million in cash. The acquisition
has been accounted for as a purchase and, accordingly, income and expenses from
the properties have been included in the Company's statement of income from the
date of purchase.
The unaudited pro forma results of operations assuming that such
acquisition occurred on January 1 of the respective periods are as follow (in
thousands, except per share amounts):
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999
---------- ----------
Proforma:
Revenue................................................... $532,142 $317,333
Income from operations.................................... 223,771 72,846
Net income................................................ 133,379 34,220
Basic earnings per common share........................... $ 3.15 $ 0.83
Diluted earnings per common share......................... $ 2.95 $ 0.81
The pro forma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisition taken
place at the beginning of the periods presented or future results of operations.
On July 15,1999, the Company completed the purchase of Gulf Australia
Resources Limited for $23 million in cash. Included in the purchase price was a
substantial amount of working capital, including an inventory of 479 MBbls of
oil. The acquisition was accounted for as a purchase and included an interest in
two producing oil fields in the Timor Sea, offshore Australia.
58
62
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. GEOGRAPHIC INFORMATION:
OTHER
UNITED STATES AUSTRALIA INTERNATIONAL TOTAL
------------- --------- ------------- --------
(IN THOUSANDS)
2000
----------------------------------------
Oil and gas revenues.................... $476,301 $50,341 $ -- $526,642
Operating expenses:
Lease operating....................... 51,509 13,863 -- 65,372
Production and other taxes............ 5,643 4,645 -- 10,288
Transportation........................ 5,984 -- -- 5,984
Ceiling test writedown................ -- -- 503 503
Depreciation, depletion and
amortization....................... 183,739 7,443 -- 191,182
Allocated income taxes................ 80,299 8,537 --
-------- ------- -------
Net income (loss) from oil and
gas operations.............. $149,127 $15,853 $ (503)
======== ======= =======
General and administrative (inclusive
of stock compensation)(1).......... 32,084
--------
Total operating expenses...... 299,429
--------
Income from operations.................. 221,229
Interest expense and dividends, net... (16,540)
--------
Income before income taxes.............. $204,689
========
Total long-lived assets................. $806,457 $10,634 $16,244 $833,315
======== ======= ======= ========
Additions to long-lived assets.......... $358,936 $13,913 $ 6,317 $379,166
======== ======= ======= ========
1999
----------------------------------------
Oil and gas revenues.................... $265,603 $22,286 $ -- $287,889
Operating expenses:
Lease operating....................... 38,562 6,999 -- 45,561
Production and other taxes............ 699 1,516 -- 2,215
Transportation........................ 5,922 -- -- 5,922
Depreciation, depletion and
amortization....................... 149,350 3,294 -- 152,644
Allocated income taxes................ 24,875 3,772 --
-------- ------- -------
Net income from oil and gas
operations.................. $ 46,195 $ 6,705 $ --
======== ======= =======
General and administrative (inclusive
of stock compensation)(1).......... 16,404
--------
Total operating expenses...... 216,824
--------
Income from operations.................. 65,143
Interest expense and dividends, net... (13,128)
--------
Income before income taxes.............. $ 52,015
========
Total long-lived assets................. $630,316 $ 4,096 $10,430 $644,842
======== ======= ======= ========
Additions to long-lived assets.......... $201,143 $ 7,390 $ 1,266 $209,799
======== ======= ======= ========
59
63
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER
UNITED STATES AUSTRALIA INTERNATIONAL TOTAL
------------- --------- ------------- --------
(IN THOUSANDS)
1998
----------------------------------------
Oil and gas revenues.................... $199,474 $ -- $ -- $199,474
Operating expenses:
Lease operating....................... 35,345 -- -- 35,345
Production and other taxes............ -- -- -- --
Transportation........................ 3,789 -- -- 3,789
Depreciation, depletion and
amortization....................... 123,147 -- -- 123,147
Ceiling test writedown................ 104,955 -- -- 104,955
Allocated income taxes................ (23,717) -- --
-------- ------- -------
Net loss from oil and gas
operations.................. $(44,405) $ -- $ --
======== ======= =======
General and administrative (inclusive
of stock compensation)(1).......... 12,070
--------
Total operating expenses...... 275,517
--------
Loss from operations.................... (79,832)
Interest expense, net................. (8,544)
--------
Loss before income taxes................ $(88,376)
========
Total long-lived assets................. $569,259 $ -- $ 9,164 $578,423
======== ======= ======= ========
Additions to long-lived assets.......... $309,260 $ -- $ 1,512 $310,772
======== ======= ======= ========
---------------
(1) General and administrative expense includes non-cash stock compensation
charges of $3,047, $1,999 and $2,222 for 2000, 1999 and 1998, respectively.
13. SUPPLEMENTAL CASH FLOW INFORMATION:
YEAR ENDED DECEMBER 31,
---------------------------
2000 1999 1998
------- ------- -------
(IN THOUSANDS)
Cash payments:
Interest and dividend payments (includes interest on
the senior notes and dividends on the convertible
trust preferred securities, net of interest
capitalized of $5,353, $2,376 and $4,369 during
2000, 1999 and 1998, respectively)................. $16,999 $11,598 $ 7,478
Income tax payments................................... 14,015 -- --
Non-cash items excluded from the statement of cash
flows:
Increase (decrease) in accrued capital expenditures... $26,712 $ 9,261 $(7,059)
Other................................................. (121) (179) (23)
60
64
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. SUBSEQUENT EVENTS:
On January 23, 2001, the Company acquired all of the outstanding capital
stock of Lariat Petroleum, Inc. ("Lariat") by merging Lariat with and into
Newfield Exploration Mid-Continent Inc., a wholly owned subsidiary of the
Company. The total consideration for the acquisition was approximately $333
million, inclusive of the assumption of debt and certain other obligations of
Lariat. The transaction will be accounted for as a purchase.
The consideration included 1.9 million shares of the Company's common
stock. The Company financed the cash portion of the consideration under a new
reserve-based revolving credit facility obtained on January 23, 2001 with The
Chase Manhattan Bank, as Agent. The banks participating in the new facility have
committed to lend the Company up to $425 million. The amount available under the
facility is subject to a calculated borrowing base determined by banks holding
75% of the aggregate commitments, which is reduced by the aggregate outstanding
principal amount of any senior notes issued by the Company ($125 million at
January 31, 2001). The borrowing base will be redetermined at least semi-
annually and, after reduction for then outstanding senior notes, was $385
million at January 31, 2001. No assurances can be given that the banks will not
elect to redetermine the borrowing base in the future. The new facility contains
restrictions on the payment of dividends and the incurrence of debt as well as
other customary covenants and restrictions. The new facility matures on January
23, 2004.
On February 22, 2001 the Company placed $175 million of 7 5/8% Senior Notes
due 2011. The offering was done under an existing shelf registration statement.
Net proceeds from the sale of the senior notes were used to repay outstanding
indebtedness under the Company's revolving credit facility. The notes were
issued at 99.931% of par to yield 7.635%, with interest payable on each March 1
and September 1, commencing September 1, 2001.
61
65
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
The results of operations by quarter for the years ended December 31, 2000
and 1999 are as follows:
2000 QUARTER ENDED
--------------------------------------------------------------------------------------------------
MARCH 31(1) JUNE 30(1) SEPTEMBER 30(1) DECEMBER 31
-------------------------- -------------------------- -------------------------- -----------
AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY
REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED
------------- ---------- ------------- ---------- ------------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Oil and gas
revenues(2)........... $95,039 $97,822 $118,878 $114,704 $151,263 $150,431 $163,685
Income from
operations............ 30,348 30,984 49,004 45,209 70,177 68,986 76,050
Net income.............. 17,123 15,183 29,561 27,056 44,338 43,552 46,558
Basic earnings per
common share.......... $ 0.41 $ 0.36 $ 0.70 $ 0.64 $ 1.04 $ 1.02 $ 1.09
Diluted earnings per
common share.......... $ 0.40 $ 0.35 $ 0.66 $ 0.60 $ 0.97 $ 0.95 $ 1.01
1999 QUARTER ENDED
-----------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31(3)
-------- ------- ------------ --------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Oil and gas revenues(2).......... $54,562 $61,688 $80,044 $91,595
Income from operations........... 3,236 9,886 22,699 29,322
Net income (loss)................ (170) 4,375 12,405 16,594
Basic earnings per common
share.......................... $ 0.00 $ 0.11 $ 0.30 $ 0.40
Diluted earnings per common
share.......................... $ 0.00 $ 0.10 $ 0.29 $ 0.39
---------------
(1) The first through third quarters of 2000 are restated to reflect the
adoption of SAB No. 101, "Revenue Recognition in Financial Statements." The
adoption of SAB No. 101 requires the Company to report crude oil inventory
associated with its Australian operations at the lower of cost or market,
which is a change from its historical policy of recording such inventory at
market value on the balance sheet, net of estimated costs to sell.
(2) As a result of the adoption of EITF No. 00-10, "Accounting for Shipping and
Handling Fees and Costs," the Company has reclassified to operating
expenses, for all periods presented, third party costs incurred to transport
production to the Company's respective sales point, instead of as a
reduction of the related revenues as previously reported. The effect of EITF
No. 00-10 reduced previously reported oil and gas revenues by $1.5 million,
$1.6 million and $1.6 million for the quarters ended March 31, June 30 and
September 30, 2000, respectively and by $1.7 million, $1.5 million, $1.4
million and $1.3 million for the quarters ended March 31, June 30, September
30 and December 31, 1999, respectively. The reclassification had no effect
on previously reported net income.
(3) Prior period financial statements have not been restated to apply SAB No.
101. However, the pro forma effect of retroactively applying SAB No. 101 to
the fourth quarter of 1999 would have reduced net income by $0.2 million, or
$0.01 per diluted share.
62
66
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED
See Note 12 to the consolidated financial statements for disclosure of the
Company's results of operations from oil and gas producing activities. Costs
incurred for oil and gas property acquisition, exploration and development
activities for each of the three years in the period ended December 31, 2000 are
as follows:
UNITED OTHER
STATES AUSTRALIA CHINA FOREIGN TOTAL
-------- --------- ------ ------- --------
(IN THOUSANDS)
2000
------------------------------------------
Property acquisition:
Unproved................................ $ 23,621 $ -- $ 375 $ 153 $ 24,149
Proved.................................. 115,567 (295) -- -- 115,272
Exploration............................... 91,177 3,760 5,286 -- 100,223
Development............................... 128,571 10,448 -- -- 139,019
-------- ------- ------ ------ --------
Total costs incurred............ $358,936 $13,913 $5,661 $ 153 $378,663
======== ======= ====== ====== ========
1999
------------------------------------------
Property acquisition:
Unproved................................ $ 5,849 $ -- $ -- $ -- $ 5,849
Proved.................................. 77,673 2,490 -- -- 80,163
Exploration............................... 46,343 3,852 641 625 51,461
Development............................... 71,278 1,048 -- -- 72,326
-------- ------- ------ ------ --------
Total costs incurred............ $201,143 $ 7,390 $ 641 $ 625 $209,799
======== ======= ====== ====== ========
1998
------------------------------------------
Property acquisition:
Unproved................................ $ 3,400 $ -- $ -- $ -- $ 3,400
Proved.................................. 86,219 -- -- -- 86,219
Exploration............................... 63,802 -- 510 1,002 65,314
Development............................... 155,839 -- -- -- 155,839
-------- ------- ------ ------ --------
Total costs incurred............ $309,260 $ -- $ 510 $1,002 $310,772
======== ======= ====== ====== ========
63
67
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
Capitalized costs for oil and gas producing activities consist of the
following at the end of each of the three years in the period ended December 31,
2000:
UNITED OTHER
STATES AUSTRALIA CHINA FOREIGN TOTAL
---------- --------- ------- ------- ----------
(IN THOUSANDS)
2000
---------------------------------------------
Proved properties............................ $1,474,925 $ 21,304 $ -- $ -- $1,496,229
Unproved properties.......................... 77,085 -- 14,236 2,008 93,329
---------- -------- ------- ------ ----------
1,552,010 21,304 14,236 2,008 1,589,558
Accumulated depreciation, depletion and
amortization............................... (745,573) (10,670) -- -- (756,243)
---------- -------- ------- ------ ----------
Net capitalized cost......................... $ 806,437 $ 10,634 $14,236 $2,008 $ 833,315
========== ======== ======= ====== ==========
1999
---------------------------------------------
Proved properties............................ $1,135,225 $ 3,538 $ -- $ -- $1,138,763
Unproved properties.......................... 57,850 3,852 8,575 1,855 72,132
---------- -------- ------- ------ ----------
1,193,075 7,390 8,575 1,855 1,210,895
Accumulated depreciation, depletion and
amortization............................... (562,759) (3,294) -- -- (566,053)
---------- -------- ------- ------ ----------
Net capitalized cost......................... $ 630,316 $ 4,096 $ 8,575 $1,855 $ 644,842
========== ======== ======= ====== ==========
1998
---------------------------------------------
Proved properties............................ $ 960,127 $ -- $ -- $ -- $ 960,127
Unproved properties.......................... 23,338 -- 7,934 1,230 32,502
---------- -------- ------- ------ ----------
983,465 -- 7,934 1,230 992,629
Accumulated depreciation, depletion and
amortization............................... (414,206) -- -- -- (414,206)
---------- -------- ------- ------ ----------
Net capitalized cost......................... $ 569,259 $ -- $ 7,934 $1,230 $ 578,423
========== ======== ======= ====== ==========
64
68
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
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 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 reported reserve estimates 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.
65
69
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 14.73
pounds per square inch absolute), including the changes therein, and proved
developed reserves at the end of each of the three years in the period ended
December 31, 2000, as estimated by the Company's petroleum engineering staff:
OIL, CONDENSATE AND
NATURAL GAS LIQUIDS
(MBBLS) NATURAL GAS (MMCF) TOTAL (BCFE)
--------------------------- ------------------------------- -------------------------------
U.S. AUSTRALIA TOTAL U.S. AUSTRALIA TOTAL U.S. AUSTRALIA TOTAL
------ --------- ------ -------- --------- -------- -------- --------- --------
Proved developed and
undeveloped reserves:
DECEMBER 31, 1997...... 16,307 -- 16,307 337,481 -- 337,481 435,323 -- 435,323
Revisions of previous
estimates............ (246) -- (246) 1,981 -- 1,981 505 -- 505
Extensions, discoveries
and other
additions............ 1,635 -- 1,635 83,777 -- 83,777 93,589 -- 93,589
Purchases of
properties........... 1,118 -- 1,118 65,672 -- 65,672 72,381 -- 72,381
Sales of properties.... -- -- -- -- -- -- -- -- --
Production............. (3,643) -- (3,643) (66,634) -- (66,634) (88,494) -- (88,494)
------ ------ ------ -------- -- -------- -------- ------ --------
DECEMBER 31, 1998...... 15,171 -- 15,171 422,277 -- 422,277 513,304 -- 513,304
Revisions of previous
estimates............ 499 -- 499 (4,359) -- (4,359) (1,365) -- (1,365)
Extensions, discoveries
and other
additions............ 1,600 -- 1,600 52,210 -- 52,210 61,808 -- 61,808
Purchases of
properties........... 6,780 7,000 13,780 60,517 -- 60,517 101,195 42,000 143,195
Sales of properties.... (926) -- (926) (3,112) -- (3,112) (8,668) -- (8,668)
Production............. (3,487) (867) (4,354) (87,360) -- (87,360) (108,282) (5,202) (113,484)
------ ------ ------ -------- -- -------- -------- ------ --------
DECEMBER 31, 1999...... 19,637 6,133 25,770 440,173 -- 440,173 557,992 36,798 594,790
Revisions of previous
estimates............ 1,264 866 2,130 (4,531) -- (4,531) 3,054 5,196 8,250
Extensions, discoveries
and other
additions............ 4,501 -- 4,501 91,096 -- 91,096 118,103 -- 118,103
Purchases of
properties........... 1,487 -- 1,487 99,531 -- 99,531 108,454 -- 108,454
Sales of properties.... (248) -- (248) (1,100) -- (1,100) (2,588) -- (2,588)
Production............. (4,090) (1,616) (5,706) (105,446) -- (105,446) (129,986) (9,696) (139,682)
------ ------ ------ -------- -- -------- -------- ------ --------
DECEMBER 31, 2000...... 22,551 5,383 27,934 519,723 -- 519,723 655,029 32,298 687,327
====== ====== ====== ======== == ======== ======== ====== ========
Proved developed
reserves:
December 31, 1997.... 15,712 -- 15,712 252,018 -- 252,018 346,290 -- 346,290
December 31, 1998.... 14,648 -- 14,648 388,040 -- 388,040 475,927 -- 475,927
December 31, 1999.... 17,123 6,133 23,256 376,820 -- 376,820 479,558 36,798 516,356
December 31, 2000.... 18,657 5,383 24,040 416,368 -- 416,368 528,310 32,298 560,608
66
70
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 SFAS No. 69 "Disclosures about Oil and Gas Producing Activities"
and based on natural gas and crude oil reserve and production volumes estimated
by the Company's petroleum engineering staff. It may be useful for certain
comparative purposes, but should not be solely relied upon in evaluating the
Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into
account in reviewing the following information: (1) future costs and selling
prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from
the rate of production assumed in the calculations; (3) a 10% discount rate 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 year-end oil and gas prices to the estimated future production of
year-end proved reserves. Future cash inflows were reduced by estimated future
development, abandonment and production costs based on year-end costs in order
to arrive at net cash flow before tax. Future income tax expense has been
computed by applying year-end statutory tax rates to aggregate future pre-tax
net cash flows, for each year reduced by the tax basis of the properties
involved and tax carryforwards. Use of a 10% discount rate is required by SFAS
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.
67
71
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:
U.S. AUSTRALIA TOTAL
---------- --------- ----------
(IN THOUSANDS)
2000
--------------------------------------------------
Future cash inflows............................... $5,709,166 $135,192 $5,844,358
Less related future:
Production costs................................ (426,987) (89,326) (516,313)
Development and abandonment costs............... (244,139) (16,320) (260,459)
---------- -------- ----------
Future net cash flows before income taxes......... 5,038,040 29,546 5,067,586
Future income tax expense......................... (1,564,431) (8,864) (1,573,295)
---------- -------- ----------
Standardized measure of future net cash flows
before discount................................. 3,473,609 20,682 3,494,291
10% annual discount for estimating timing of cash
flows........................................... (820,256) (3,777) (824,033)
---------- -------- ----------
Standardized measure of discounted future net cash
flows........................................... $2,653,353 $ 16,905 $2,670,258
========== ======== ==========
1999
--------------------------------------------------
Future cash inflows............................... $1,552,273 $156,247 $1,708,520
Less related future:
Production costs................................ (239,010) (95,252) (334,262)
Development and abandonment costs............... (205,402) (31,324) (236,726)
---------- -------- ----------
Future net cash flows before income taxes......... 1,107,861 29,671 1,137,532
Future income tax expense......................... (214,365) (9,871) (224,236)
---------- -------- ----------
Standardized measure of future net cash flows
before discount................................. 893,496 19,800 913,296
10% annual discount for estimating timing of cash
flows........................................... (180,431) (346) (180,777)
---------- -------- ----------
Standardized measure of discounted future net cash
flows........................................... $ 713,065 $ 19,454 $ 732,519
========== ======== ==========
1998
--------------------------------------------------
Future cash inflows............................... $1,047,290 $ -- $1,047,290
Less related future:
Production costs................................ (203,717) -- (203,717)
Development and abandonment costs............... (162,005) -- (162,005)
---------- -------- ----------
Future net cash flows before income taxes......... 681,568 -- 681,568
Future income tax expense......................... (122,304) -- (122,304)
---------- -------- ----------
Standardized measure of future net cash flows
before discount................................. 559,264 -- 559,264
10% annual discount for estimating timing of cash
flows........................................... (108,108) -- (108,108)
---------- -------- ----------
Standardized measure of discounted future net cash
flows........................................... $ 451,156 $ -- $ 451,156
========== ======== ==========
68
72
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED -- (CONTINUED)
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:
U.S. AUSTRALIA TOTAL
----------- --------- -----------
(IN THOUSANDS)
2000
---------------------------------------------------------
Beginning of the period.................................. $ 713,065 $19,454 $ 732,519
Revisions of previous estimates:
Changes in prices and costs............................ 1,866,958 (5,791) 1,861,167
Changes in quantities.................................. 18,849 6,680 25,529
Changes in future development costs.................... -- 15,004 15,004
Development costs incurred during the period............. 69,232 3,260 72,492
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related
costs.................................................. 611,719 -- 611,719
Purchases of reserves in place........................... 524,675 -- 524,675
Accretion of discount.................................... 88,414 2,915 91,329
Sales of oil and gas, net of production costs............ (413,165) (28,193) (441,358)
Net change in income taxes............................... (1,023,931) 834 (1,023,097)
Production timing and other.............................. 197,537 2,742 200,279
----------- ------- -----------
Net increase (decrease).................................. 1,940,288 (2,549) 1,937,739
----------- ------- -----------
End of the period........................................ $ 2,653,353 $16,905 $ 2,670,258
=========== ======= ===========
1999
---------------------------------------------------------
Beginning of the period.................................. $ 451,156 $ -- $ 451,156
Revisions of previous estimates:
Changes in prices and costs............................ 229,539 -- 229,539
Changes in quantities.................................. (2,553) -- (2,553)
Changes in future development costs.................... (4,069) -- (4,069)
Development costs incurred during the period............. 21,658 -- 21,658
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related
costs.................................................. 100,907 -- 100,907
Purchases of reserves in place........................... 145,515 33,225 178,740
Accretion of discount.................................... 54,982 -- 54,982
Sales of oil and gas, net of production costs............ (220,420) (13,771) (234,191)
Net change in income taxes............................... (72,414) -- (72,414)
Production timing and other.............................. 8,764 -- 8,764
----------- ------- -----------
Net increase............................................. 261,909 19,454 281,363
----------- ------- -----------
End of the period........................................ $ 713,065 $19,454 $ 732,519
=========== ======= ===========
1998
---------------------------------------------------------
Beginning of the period.................................. $ 502,948 $ -- $ 502,948
Revisions of previous estimates:
Changes in prices and costs............................ (226,749) -- (226,749)
Changes in quantities.................................. 662 -- 662
Changes in future development costs.................... 5,401 -- 5,401
Development costs incurred during the period............. 55,153 -- 55,153
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related
costs.................................................. 117,837 -- 117,837
Purchases of reserves in place........................... 48,889 -- 48,889
Accretion of discount.................................... 65,467 -- 65,467
Sales of oil and gas, net of production costs............ (160,340) -- (160,340)
Net change in income taxes............................... 53,059 -- 53,059
Production timing and other.............................. (11,171) -- (11,171)
----------- ------- -----------
Net decrease............................................. (51,792) -- (51,792)
----------- ------- -----------
End of the period........................................ $ 451,156 $ -- $ 451,156
=========== ======= ===========
69
73
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
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, please see our definitive Proxy Statement for our
Annual Meeting of Stockholders to be held on May 3, 2001 which has been filed
with the SEC and is incorporated herein by reference, and "Part I -- ITEM 4A.
EXECUTIVE OFFICERS."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) 1. FINANCIAL STATEMENTS
The following financial statements and the report of our management
and independent accountants thereon are included in this report:
Management Report on Financial Statements
Report of Independent Accountants
Consolidated Balance Sheet as of the fiscal years ended December 31,
2000 and 1999
Consolidated Statement of Income for each of the three years in the
period ended December 31, 2000
Consolidated Statement of Stockholders' Equity for each of the three
years in the period ended December 31, 2000
Consolidated Statement of Cash Flows for each of the three years in the
period ended December 31, 2000
Notes to the Consolidated Financial Statements
Supplementary Oil and Gas Disclosures
2. FINANCIAL STATEMENT SCHEDULES
Financial statement schedules listed under SEC rules but not
included in this report are omitted because they are not applicable or
the required information is provided in the notes to the financial
statements.
3. EXHIBITS
EXHIBIT
NUMBER TITLE
------- -----
3.1 -- Second Restated Certificate of Incorporation of Newfield
(incorporated by reference to Exhibit 3.1 to Newfield's
Annual Report on Form 10-K for the year ended December
31, 1999 (File No. 1-12534))
3.2 -- Certificate of Amendment to Second Restated Certificate
of Incorporation of Newfield dated May 15, 1997
(incorporated by reference to Exhibit 3.1.1 to the
Company's Registration Statement on Form S-3
(Registration No. 333-32582))
70
74
EXHIBIT
NUMBER TITLE
------- -----
3.3 -- Restated Bylaws of Newfield as amended by Amendment No. 1
thereto adopted January 31, 2000 (incorporated by
reference to Exhibit 3.3 to Newfield's Annual Report on
Form 10-K for the year ended December 31, 1999 (File No.
1-12534))
3.4 -- Certificate of Designation of Series A Junior
Participating Preferred Stock, par value $0.01 per share,
setting forth the terms of the Series A Junior
Participating Preferred Stock, par value $0.01 per share
(incorporated by reference to Exhibit 3.5 to Newfield's
Annual Report on Form 10-K for the year ended December
31, 1998 (File No. 1-12534))
4.1 -- Rights Agreement, dated as of February 12, 1999, between
Newfield and ChaseMellon Shareholder Services L.L.C., as
Rights Agent, specifying the terms of the Rights to
Purchase Series A Junior Participating Preferred Stock,
par value $0.01 per share, of Newfield (incorporated by
reference to Exhibit 1 to Newfield's Registration
Statement on Form 8-A filed with the Securities and
Exchange Commission on February 18, 1999 (File No.
1-12534))
4.2 -- Indenture dated as of October 15, 1997 among Newfield, as
issuer, and First Union National Bank, as trustee
(incorporated by reference to Exhibit 4.3 to Newfield's
Registration Statement on Form S-4 (Registration No.
333-39563))
4.3 -- Amended and Restated Trust Agreement of Newfield
Financial Trust I, dated as of August 13, 1999
(incorporated by reference to Exhibit 4.1 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on August 13, 1999 (File No.
1-12534))
4.4 -- Form of Preferred Security of Newfield Financial Trust I
(incorporated by reference to Exhibit 4.2 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on August 13, 1999 (File No.
1-12534))
4.5 -- Junior Subordinated Convertible Indenture, dated as of
August 13, 1999, between Newfield and First Union
National Bank, as Trustee (incorporated by reference to
Exhibit 4.3 of Newfield's Current Report on Form 8-K
filed with the Securities and Exchange Commission on
August 13, 1999 (File No. 1-12534))
4.6 -- Form of 6 1/2% Junior Subordinated Convertible Debenture,
Series A due 2029 (incorporated by reference to Exhibit
4.4 of Newfield's Current Report on Form 8-K filed with
the Securities and Exchange Commission on August 13, 1999
(File No. 1-12534))
4.7 -- Guarantee Agreement, dated as of August 13, 1999,
relating to Newfield Financial Trust I (incorporated by
reference to Exhibit 4.5 of Newfield's Current Report on
Form 8-K filed with the Securities and Exchange
Commission on August 13, 1999 (File No. 1-12534))
4.8 -- Senior Indenture dated as of February 28, 2001 between
Newfield and First Union National Bank, as Trustee
(incorporated by reference to Exhibit 4.1 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on February 28, 2001 (File No.
1-12534))
+10.1 -- Newfield Exploration Company 1989 Stock Option Plan
(incorporated by reference to Exhibit 10.1 to Newfield'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 Newfield's
Registration Statement on Form S-1 (Registration No.
33-69540))
71
75
EXHIBIT
NUMBER TITLE
------- -----
+10.3 -- Newfield Exploration Company 1991 Stock Option Plan
(incorporated by reference to Exhibit 10.3 to Newfield'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 Newfield'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 Newfield's
Registration Statement on Form S-1 (Registration No.
33-69540))
+10.6 -- Newfield Exploration Company 1995 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1 to Newfield's
Registration Statement on Form S-8 (Registration No.
33-92182))
+10.7 -- Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (Restated) (incorporated by
reference to Exhibit 10.10 to Newfield's Registration
Statement on Form S-3 (Registration No. 333-32587))
+10.8 -- Newfield Exploration Company Deferred Compensation Plan
(incorporated by reference to Exhibit 10.11 to Newfield's
Registration Statement on Form S-3 (Registration No.
333-32587))
+10.9 -- Asset Purchase Agreement among Newfield Offshore Inc.,
Huffco and Huffco Turkey, Inc. dated as of May 12, 1997
(without exhibits and schedules) (incorporated by
reference to Exhibit 10.14 to Newfield's Registration
Statement on Form S-3 (Registration No. 333-32587))
+10.10 -- Resolution of Members Establishing the Preferences,
Limitations and Relative Rights of Series "A" Preferred
Shares of Huffco China, LDC dated May 14, 1997
(incorporated by reference to Exhibit 10.15 to Newfield's
Registration Statement on Form S-3 (Registration No.
333-32587))
+10.11 -- Guaranty Agreement among Newfield, Newfield Offshore
Inc., Huffco and Huffco Turkey, Inc. dated as of May 15,
1997 (incorporated by reference to Exhibit 10.16 to
Newfield's Registration Statement on Form S-3
(Registration No. 333-32587))
+10.12 -- Newfield Exploration Company 1998 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1.1 to Newfield's
Registration Statement on Form S-8 (Registration No.
333-59383))
+10.13 -- Amendment of 1998 Omnibus Stock Plan, dated May 7, 1998
(incorporated by reference to Exhibit 4.1.2 to Newfield's
Registration Statement on Form S-8 (Registration No.
333-59383))
+10.14 -- Newfield Exploration Company 2000 Non-Employee Director
Restricted Stock Plan (incorporated by reference to
Exhibit 10.18 to Newfield's Annual Report on Form 10-K
for the year ended December 31, 1999 (File No. 1-12534))
+10.15 -- Newfield Exploration Company 2001 Employee Stock Purchase
Plan (incorporated by reference to Exhibit 10.19 to
Newfield's Annual Report on Form 10-K for the year ended
December 31, 1999 (File No. 1-12534))
+10.16 -- Newfield Exploration Company 2000 Omnibus Stock Plan
(incorporated by reference to Exhibit 10.20 to Newfield's
Annual Report on Form 10-K for the year ended December
31, 1999 (File No. 1-12534))
+10.17 -- Employment Agreement between Newfield and Joe B. Foster
dated January 31, 2000 (incorporated by reference to
Exhibit 10 to Newfield's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 2000 (File No.
1-12534))
72
76
EXHIBIT
NUMBER TITLE
------- -----
+10.18 -- Amended and Restated Agreement and Plan of Merger, dated
as of January 19, 2001, by and among Newfield, Newfield
Exploration Mid-Continent Inc., Lariat Petroleum, Inc.
("Lariat") and the former stockholders of Lariat
(incorporated by reference to Exhibit 10.1 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on February 7, 2001 (File No.
1-12534))
+10.19 -- Registration Rights Agreement, dated as of January 23,
2001, by and among Newfield and certain of the former
stockholders of Lariat (incorporated by reference to
Exhibit 10.3 of Newfield's Current Report on Form 8-K
filed with the Securities and Exchange Commission on
February 7, 2001 (File No. 1-12534))
+10.20 -- Employment Agreement, dated April 1, 1997, by and between
Lariat and Raymond A. Foutch (the "Foutch Employment
Agreement") (incorporated by reference to Exhibit 10.4.1
of Newfield's Current Report on Form 8-K filed with the
Securities and Exchange Commission on February 7, 2001
(File No. 1-12534))
+10.21 -- Letter Agreement, dated December 28, 2000, amending the
Foutch Employment Agreement (incorporated by reference to
Exhibit 10.4.2 of Newfield's Current Report on Form 8-K
filed with the Securities and Exchange Commission on
February 7, 2001 (File No. 1-12534))
10.22 -- Credit Agreement, dated as of January 23, 2001, among
Newfield, The Chase Manhattan Bank, as Agent, and the
banks signatory thereto (the "Credit Agreement")
(incorporated by reference to Exhibit 10.2.1 of
Newfield's Current Report on Form 8-K filed with the
Securities and Exchange Commission on February 7, 2001
(File No. 1-12534))
10.23 -- First Amendment Agreement, dated as of January 31, 2001,
amending the Credit Agreement (incorporated by reference
to Exhibit 10.2.2 of Newfield's Current Report on Form
8-K filed with the Securities and Exchange Commission on
February 7, 2001 (File No. 1-12534))
*21.1 -- List of Significant Subsidiaries
*23.1 -- Consent of PricewaterhouseCoopers LLP
---------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
(B) REPORTS ON FORM 8-K
We did not file any reports on Form 8-K during the fourth quarter of 2000.
73
77
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, on the 17th day of
March, 2001.
NEWFIELD EXPLORATION COMPANY
By: /s/ DAVID A. TRICE
----------------------------------
David A. Trice
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant in the capacities indicated and on the 17th day of March, 2001.
SIGNATURE TITLE
--------- -----
/s/ DAVID A. TRICE President and Chief Executive Officer and
----------------------------------------------------- Director (Principal Executive Officer)
David A. Trice
/s/ TERRY W. RATHERT Vice President and Chief Financial Officer
----------------------------------------------------- (Principal Financial Officer)
Terry W. Rathert
/s/ RONALD P. LEGE Controller (Principal Accounting Officer)
-----------------------------------------------------
Ronald P. Lege
/s/ JOE B. FOSTER Director
-----------------------------------------------------
Joe B. Foster
/s/ ROBERT W. WALDRUP Director
-----------------------------------------------------
Robert W. Waldrup
/s/ PHILIP J. BURGUIERES Director
-----------------------------------------------------
Philip J. Burguieres
/s/ CHARLES W. DUNCAN, JR. Director
-----------------------------------------------------
Charles W. Duncan, Jr.
/s/ DENNIS HENDRIX Director
-----------------------------------------------------
Dennis Hendrix
/s/ TERRY HUFFINGTON Director
-----------------------------------------------------
Terry Huffington
/s/ HOWARD H. NEWMAN Director
-----------------------------------------------------
Howard H. Newman
/s/ THOMAS G. RICKS Director
-----------------------------------------------------
Thomas G. Ricks
/s/ C. E. SHULTZ Director
-----------------------------------------------------
C. E. Shultz
74
78
INDEX TO EXHIBITS
EXHIBIT
NUMBER TITLE
------- -----
3.1 -- Second Restated Certificate of Incorporation of Newfield
(incorporated by reference to Exhibit 3.1 to Newfield's
Annual Report on Form 10-K for the year ended December
31, 1999 (File No. 1-12534))
3.2 -- Certificate of Amendment to Second Restated Certificate
of Incorporation of Newfield dated May 15, 1997
(incorporated by reference to Exhibit 3.1.1 to the
Company's Registration Statement on Form S-3
(Registration No. 333-32582))
3.3 -- Restated Bylaws of Newfield as amended by Amendment No. 1
thereto adopted January 31, 2000 (incorporated by
reference to Exhibit 3.3 to Newfield's Annual Report on
Form 10-K for the year ended December 31, 1999 (File No.
1-12534))
3.4 -- Certificate of Designation of Series A Junior
Participating Preferred Stock, par value $0.01 per share,
setting forth the terms of the Series A Junior
Participating Preferred Stock, par value $0.01 per share
(incorporated by reference to Exhibit 3.5 to Newfield's
Annual Report on Form 10-K for the year ended December
31, 1998 (File No. 1-12534))
4.1 -- Rights Agreement, dated as of February 12, 1999, between
Newfield and ChaseMellon Shareholder Services L.L.C., as
Rights Agent, specifying the terms of the Rights to
Purchase Series A Junior Participating Preferred Stock,
par value $0.01 per share, of Newfield (incorporated by
reference to Exhibit 1 to Newfield's Registration
Statement on Form 8-A filed with the Securities and
Exchange Commission on February 18, 1999 (File No.
1-12534))
4.2 -- Indenture dated as of October 15, 1997 among Newfield, as
issuer, and First Union National Bank, as trustee
(incorporated by reference to Exhibit 4.3 to Newfield's
Registration Statement on Form S-4 (Registration No.
333-39563))
4.3 -- Amended and Restated Trust Agreement of Newfield
Financial Trust I, dated as of August 13, 1999
(incorporated by reference to Exhibit 4.1 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on August 13, 1999 (File No.
1-12534))
4.4 -- Form of Preferred Security of Newfield Financial Trust I
(incorporated by reference to Exhibit 4.2 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on August 13, 1999 (File No.
1-12534))
4.5 -- Junior Subordinated Convertible Indenture, dated as of
August 13, 1999, between Newfield and First Union
National Bank, as Trustee (incorporated by reference to
Exhibit 4.3 of Newfield's Current Report on Form 8-K
filed with the Securities and Exchange Commission on
August 13, 1999 (File No. 1-12534))
4.6 -- Form of 6 1/2% Junior Subordinated Convertible Debenture,
Series A due 2029 (incorporated by reference to Exhibit
4.4 of Newfield's Current Report on Form 8-K filed with
the Securities and Exchange Commission on August 13, 1999
(File No. 1-12534))
4.7 -- Guarantee Agreement, dated as of August 13, 1999,
relating to Newfield Financial Trust I (incorporated by
reference to Exhibit 4.5 of Newfield's Current Report on
Form 8-K filed with the Securities and Exchange
Commission on August 13, 1999 (File No. 1-12534))
4.8 -- Senior Indenture dated as of February 28, 2001 between
Newfield and First Union National Bank, as Trustee
(incorporated by reference to Exhibit 4.1 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on February 28, 2001 (File No.
1-12534))
79
EXHIBIT
NUMBER TITLE
------- -----
+10.1 -- Newfield Exploration Company 1989 Stock Option Plan
(incorporated by reference to Exhibit 10.1 to Newfield'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 Newfield'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 Newfield'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 Newfield'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 Newfield's
Registration Statement on Form S-1 (Registration No.
33-69540))
+10.6 -- Newfield Exploration Company 1995 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1 to Newfield's
Registration Statement on Form S-8 (Registration No.
33-92182))
+10.7 -- Newfield Exploration Company 1995 Non-Employee Director
Restricted Stock Plan (Restated) (incorporated by
reference to Exhibit 10.10 to Newfield's Registration
Statement on Form S-3 (Registration No. 333-32587))
+10.8 -- Newfield Exploration Company Deferred Compensation Plan
(incorporated by reference to Exhibit 10.11 to Newfield's
Registration Statement on Form S-3 (Registration No.
333-32587))
+10.9 -- Asset Purchase Agreement among Newfield Offshore Inc.,
Huffco and Huffco Turkey, Inc. dated as of May 12, 1997
(without exhibits and schedules) (incorporated by
reference to Exhibit 10.14 to Newfield's Registration
Statement on Form S-3 (Registration No. 333-32587))
+10.10 -- Resolution of Members Establishing the Preferences,
Limitations and Relative Rights of Series "A" Preferred
Shares of Huffco China, LDC dated May 14, 1997
(incorporated by reference to Exhibit 10.15 to Newfield's
Registration Statement on Form S-3 (Registration No.
333-32587))
+10.11 -- Guaranty Agreement among Newfield, Newfield Offshore
Inc., Huffco and Huffco Turkey, Inc. dated as of May 15,
1997 (incorporated by reference to Exhibit 10.16 to
Newfield's Registration Statement on Form S-3
(Registration No. 333-32587))
+10.12 -- Newfield Exploration Company 1998 Omnibus Stock Plan
(incorporated by reference to Exhibit 4.1.1 to Newfield's
Registration Statement on Form S-8 (Registration No.
333-59383))
+10.13 -- Amendment of 1998 Omnibus Stock Plan, dated May 7, 1998
(incorporated by reference to Exhibit 4.1.2 to Newfield's
Registration Statement on Form S-8 (Registration No.
333-59383))
+10.14 -- Newfield Exploration Company 2000 Non-Employee Director
Restricted Stock Plan (incorporated by reference to
Exhibit 10.18 Annual Report on Form 10-K for the year
ended December 31, 1999 (File No. 1-12534))
+10.15 -- Newfield Exploration Company 2001 Employee Stock Purchase
Plan (incorporated by reference to Exhibit 10.19 to
Newfield's Annual Report on Form 10-K for the year ended
December 31, 1999 (File No. 1-12534))
80
EXHIBIT
NUMBER TITLE
------- -----
+10.16 -- Newfield Exploration Company 2000 Omnibus Stock Plan
(incorporated by reference to Exhibit 10.20 to Newfield's
Annual Report on Form 10-K for the year ended December
31, 1999 (File No. 1-12534))
+10.17 -- Employment Agreement between Newfield and Joe B. Foster
dated January 31, 2000 (incorporated by reference to
Exhibit 10 to Newfield's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 2000 (File No.
1-12534))
+10.18 -- Amended and Restated Agreement and Plan of Merger, dated
as of January 19, 2001, by and among Newfield, Newfield
Exploration Mid-Continent Inc., Lariat Petroleum, Inc.
("Lariat") and the former stockholders of Lariat
(incorporated by reference to Exhibit 10.1 of Newfield's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on February 7, 2001 (File No.
1-12534))
+10.19 -- Registration Rights Agreement, dated as of January 23,
2001, by and among Newfield and certain of the former
stockholders of Lariat (incorporated by reference to
Exhibit 10.3 of Newfield's Current Report on Form 8-K
filed with the Securities and Exchange Commission on
February 7, 2001 (File No. 1-12534))
+10.20 -- Employment Agreement, dated April 1, 1997, by and between
Lariat and Raymond A. Foutch (the "Foutch Employment
Agreement") (incorporated by reference to Exhibit 10.4.1
of Newfield's Current Report on Form 8-K filed with the
Securities and Exchange Commission on February 7, 2001
(File No. 1-12534))
+10.21 -- Letter Agreement, dated December 28, 2000, amending the
Foutch Employment Agreement (incorporated by reference to
Exhibit 10.4.2 of Newfield's Current Report on Form 8-K
filed with the Securities and Exchange Commission on
February 7, 2001 (File No. 1-12534))
10.22 -- Credit Agreement, dated as of January 23, 2001, among
Newfield, The Chase Manhattan Bank, as Agent, and the
banks signatory thereto (the "Credit Agreement")
(incorporated by reference to Exhibit 10.2.1 of
Newfield's Current Report on Form 8-K filed with the
Securities and Exchange Commission on February 7, 2001
(File No. 1-12534))
10.23 -- First Amendment Agreement, dated as of January 31, 2001,
amending the Credit Agreement (incorporated by reference
to Exhibit 10.2.2 of Newfield's Current Report on Form
8-K filed with the Securities and Exchange Commission on
February 7, 2001 (File No. 1-12534))
*21.1 -- List of Significant Subsidiaries
*23.1 -- Consent of PricewaterhouseCoopers LLP
---------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.