UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE YEAR ENDED DECEMBER 31, 2001
COMMISSION FILE NO. 1-8968
ANADARKO PETROLEUM CORPORATION
1201 LAKE ROBBINS DRIVE, THE WOODLANDS, TEXAS 77380-1046
(832) 636-1000
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INCORPORATED IN THE STATE OF DELAWARE EMPLOYER IDENTIFICATION NO. 76-0146568
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, par value $0.10 per share
Preferred Stock Purchase Rights
The above Securities are listed on the New York Stock Exchange.
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 the 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 on February 28, 2002 was $12,873,673,000.
The number of shares outstanding of the Company's common stock as of
February 28, 2002 is shown below:
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TITLE OF CLASS NUMBER OF SHARES OUTSTANDING
Common Stock, par value $0.10 per share 248,046,910
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PART OF
FORM 10-K DOCUMENTS INCORPORATED BY REFERENCE
Part III Portions of the Proxy Statement, dated March 25, 2002, for
the Annual Meeting of Stockholders of Anadarko Petroleum
Corporation to be held April 25, 2002.
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TABLE OF CONTENTS
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PAGE
PART I
Item 1. Business 2
General 2
Oil and Gas Properties and Activities 2
Proved Reserves and Future Net Cash Flows 2
Sales Volumes and Prices 3
Properties and Activities -- United States 4
Properties and Activities -- Canada 14
Properties and Activities -- Algeria 16
Properties and Activities -- Other International 19
Drilling Programs 21
Drilling Statistics 21
Productive Wells 22
Marketing and Gathering Properties and Activities 23
Minerals Properties and Activities 23
Segment and Geographic Information 24
Employees 24
Regulatory Matters and Additional Factors Affecting Business 24
Title to Properties 24
Capital Spending 24
Ratios of Earnings to Fixed Charges and Earnings to
Combined Fixed Charges and Preferred Stock Dividends 24
Item 2. Properties 25
Item 3. Legal Proceedings 25
Item 4. Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant 27
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 29
Item 6. Selected Financial Data 30
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 31
Item 7a. Quantitative and Qualitative Disclosures About Market Risk 55
Item 8. Financial Statements and Supplementary Data 61
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 119
PART III
Item 10. Directors and Executive Officers of the Registrant 119
Item 11. Executive Compensation 119
Item 12. Security Ownership of Certain Beneficial Owners and
Management 119
Item 13. Certain Relationships and Related Transactions 119
PART IV
Item 14. Exhibits and Reports on Form 8-K 120
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1
PART I
ITEM 1. BUSINESS
GENERAL
Anadarko Petroleum Corporation is among the largest independent oil and gas
exploration and production companies in the world, with 2.3 billion barrels of
oil equivalent (BOE) of proved reserves as of December 31, 2001. The Company's
major areas of operations are located in the United States, primarily in Texas,
Louisiana, the mid-continent region and the western states, Alaska and in the
shallow and deep waters of the Gulf of Mexico, as well as in Canada and Algeria.
The Company is also active in Venezuela, Qatar, Oman, Egypt, Australia, Tunisia,
Congo and Gabon. The Company actively markets natural gas, oil and natural gas
liquids (NGLs) production and owns and operates gas gathering systems in its
core producing areas. In addition, the Company engages in the hard minerals
business through non-operated joint ventures and royalty arrangements in several
coal, trona (natural soda ash) and industrial mineral mines located on lands
within and adjacent to its Land Grant holdings primarily in Wyoming, Colorado
and Utah.
On July 14, 2000, the Company merged with Union Pacific Resources Group
Inc., subsequently renamed RME Holding Company (RME). The merger was treated as
a tax-free reorganization and accounted for as a purchase business combination.
As such, the financial and operating results and property descriptions presented
here, unless expressly noted otherwise, are those of Anadarko on a stand-alone
basis for the periods up to July 14, 2000 and of the combined Company from that
date forward.
The principal subsidiaries of Anadarko are: RME Petroleum Company; RME
Holding Company; Anadarko Canada Energy Ltd.; Anadarko Canada Corporation
(Anadarko Canada); RME Land Corp.; and, Anadarko Algeria Company, LLC (Anadarko
Algeria). Unless the context otherwise requires, the terms "Anadarko" or
"Company" refer to Anadarko and its subsidiaries. The Company's corporate
headquarters are located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380,
where the telephone number is (832) 636-1000.
OIL AND GAS PROPERTIES AND ACTIVITIES
PROVED RESERVES AND FUTURE NET CASH FLOWS
As of December 31, 2001, Anadarko had proved reserves of 1.1 billion
barrels of crude oil, condensate and NGLs and 7.0 trillion cubic feet (Tcf) of
natural gas. Combined, these proved reserves are equivalent to 2.3 billion
barrels of oil or 13.8 Tcf of gas. The Company's reserves have grown
significantly over the past three years due to the RME merger in 2000, the
acquisitions of Berkley Petroleum Corp. (Berkley) and Gulfstream Resources
Canada Limited (Gulfstream) in 2001, substantial natural gas reserves discovered
in the Gulf of Mexico, Canada and onshore in the U.S., crude oil reserves
discovered in Algeria and Alaska and through other acquisitions of producing
properties.
As of December 31, 2001, Anadarko had proved developed reserves of 5.3 Tcf
of natural gas and 626 million barrels (MMBbls) of crude oil, condensate and
NGLs. Proved developed reserves comprise 65% of the total proved reserves.
The Company's estimates of proved reserves and proved developed reserves at
December 31, 2001, 2000 and 1999 and changes in proved reserves during the last
three years are contained in the Supplemental Information on Oil and Gas
Exploration and Production Activities -- Unaudited (Supplemental Information) in
the Anadarko Petroleum Corporation 2001 Consolidated Financial Statements
(Consolidated Financial Statements) under Item 8 of this Form 10-K Annual Report
(Form 10-K). The Company files annual estimates of certain proved oil and gas
reserves with the U.S. Department of Energy, which are within 5% of the amounts
included in the above estimates. See Critical Accounting Policies under Item 7
of this Form 10-K.
Also contained in the Supplemental Information in the Consolidated
Financial Statements are the Company's estimates of future net cash flows,
discounted future net cash flows before income taxes and discounted future net
cash flows after income taxes from proved reserves.
2
SALES VOLUMES AND PRICES
The following table shows the Company's annual sales volumes. Volumes for
natural gas are in billion cubic feet (Bcf) at a pressure base of 14.73 pounds
per square inch and volumes for oil, condensate and NGLs are in MMBbls. Total
volumes are in million barrels of oil equivalent (MMBOE). For this computation,
six thousand cubic feet (Mcf) of gas is the energy equivalent of one barrel of
oil, condensate or NGLs.
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2001 2000 1999
---- ---- ----
UNITED STATES
Natural gas (Bcf) 573 338 170
Oil and condensate (MMBbls) 34 15 9
Natural gas liquids (MMBbls) 14 12 7
Total (MMBOE) 144 83 44
CANADA*
Natural gas (Bcf) 121 46 --
Oil and condensate (MMBbls) 13 4 --
Natural gas liquids (MMBbls) 1 -- --
Total (MMBOE) 34 12 --
ALGERIA
Oil and condensate (MMBbls) 8 10 6
Total (MMBOE) 8 10 6
OTHER INTERNATIONAL*
Natural gas (Bcf) 1 1 --
Oil and condensate (MMBbls) 13 7 --
Total (MMBOE) 13 7 --
TOTAL
Natural gas (Bcf) 695 385 170
Oil and condensate (MMBbls) 68 36 15
Natural gas liquids (MMBbls) 15 12 7
Total (MMBOE) 199 112 50
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* In July 2000, Anadarko acquired its production in Canada and other
international areas as a result of the merger with RME.
3
The following table shows the Company's annual average wellhead sales
prices and average production costs. The average sales prices include realized
gains and losses for derivative contracts the Company enters to manage price
risk related to the Company's sales volumes.
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2001 2000 1999
------ ------ ------
UNITED STATES
Sales price
Natural gas (per Mcf) $ 4.15 $ 4.11 $ 2.08
Oil and condensate (per barrel) 22.92 28.72 15.79
Natural gas liquids (per barrel) 16.39 21.65 13.40
Production cost (per BOE) $ 4.60 $ 4.91 $ 4.28
CANADA*
Sales price
Natural gas (per Mcf) $ 4.27 $ 4.38 --
Oil and condensate (per barrel) 17.33 27.38 --
Natural gas liquids (per barrel) 18.32 -- --
Production cost (per BOE) $ 5.53 $ 6.80 --
ALGERIA
Sales price
Oil and condensate (per barrel) $23.97 $28.76 $18.23
Production cost (per BOE) $ 2.33 $ 2.61 $ 1.84
OTHER INTERNATIONAL*
Sales price
Natural gas (per Mcf) $ 1.22 $ 1.08 --
Oil and condensate (per barrel) 14.35 18.35 --
Production cost (per BOE) $ 5.64 $ 8.24 --
TOTAL
Sales price
Natural gas (per Mcf) $ 4.16 $ 4.13 $ 2.08
Oil and condensate (per barrel) 20.32 26.49 16.83
Natural gas liquids (per barrel) 16.51 21.70 13.40
Production cost (per BOE) $ 4.73 $ 5.16 $ 3.97
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* In July 2000, Anadarko acquired its production in Canada and other
international areas as a result of the merger with RME.
Additional information on volumes, prices and markets is contained in
Financial Results and Marketing Strategies under Item 7 of this Form 10-K.
Information on major customers is contained in Note 10 of the Notes to
Consolidated Financial Statements under Item 8 of this Form 10-K.
PROPERTIES AND ACTIVITIES -- UNITED STATES
United States reserves comprised 61% of Anadarko's total proved reserves at
year-end 2001 compared to 64% in 2000 and 71% in 1999. The accompanying maps
illustrate by state Anadarko's undeveloped and developed lease and fee acreage,
number of net producing wells and other data relevant to its domestic onshore
and offshore oil and gas operations.
ONSHORE -- LOWER 48 STATES
OVERVIEW About 50% of the Company's proved reserves are located onshore in the
Lower 48 states, with operations primarily in Texas, Louisiana, the
mid-continent region and western states. In 2001, average production from the
Company's onshore properties was 1,241 million cubic feet per day (MMcf/d) of
gas and 90 thousand barrels per day (MBbls/d) of crude oil, condensate and NGLs,
or 55% of the Company's total production volumes. During 2001, Anadarko
participated in a total of 855 wells in the Lower 48 states with a success rate
of 96%. Drilling results included 673 gas wells, 148 oil wells and 34 dry holes.
Anadarko has
4
[ONSHORE PROPERTIES MAP]
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NET NET NET NET
DEVELOPED UNDEVELOPED FEE PRODUCING
ACRES ACRES ACRES WELLS
--------- ----------- --------- ---------
ONSHORE:
United States
Alabama 515 181 11,473 --
Alaska* 7,385 481,233 7,978 5
Arkansas 1,100 835 332,709 --
California 473 11,128 3,642 --
Colorado 20,004 11,219 2,889,218 176
Florida -- -- 5,062 --
Georgia -- -- 2,838 --
Idaho -- -- 711 --
Illinois -- -- 7,738 --
Indiana -- 913 9,913 --
Iowa -- -- 128 --
Kansas* 365,330 261,938 52,013 1,825
Louisiana* 134,317 138,136 13,423 170
Michigan -- 21 -- --
Mississippi 836 4,849 63,879 2
Missouri -- -- 10,522 --
Montana 10 250 39 --
Nebraska 926 1,621 28,298 --
New Mexico* 23,673 6,049 346 155
Nevada -- -- 440 --
Oklahoma* 199,031 97,220 35,448 1,169
Oregon -- -- 741 --
South Carolina -- -- 2,734 --
South Dakota -- -- 3,001 --
Tennessee -- -- 902 --
Texas* 1,085,001 703,513 182,441 6,363
Utah* 22,212 8,387 690,195 160
Virginia -- -- 14 --
Washington -- -- 2,521 --
West Virginia -- 330 -- --
Wyoming* 47,369 336,368 4,160,577 714
OFFICE LOCATIONS:
United States
Amarillo,Texas
Anchorage, Alaska
Midland, Texas
The Woodlands, Texas
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* Drilling activities were conducted in these areas in 2001.
5
2,322,000 gross (1,583,000 net) undeveloped lease acres, 2,714,000 gross
(1,901,000 net) developed lease acres and 9,532,000 gross (8,511,000 net) fee
acres onshore in the Lower 48 states.
EAST TEXAS AND LOUISIANA
Bossier Play-Overview Anadarko has taken a number of steps over the past few
years to significantly expand the scope of its Bossier operations and to
position the Company to build on an already solid record of success. Since
operations began in 1996, the Company has achieved a development success rate of
nearly 100% and expanded the play from east Texas into north Louisiana. The
Bossier play consists of multiple fields and multiple pay zones, including the
Cotton Valley Bossier Sands, Rodessa, Pettet, Travis Peak and Cotton Valley Lime
formations. The majority of the Company's production is from the Bossier Sand
interval. Bossier production is typical of a "tight" gas reservoir -- one with
low porosity and permeability. Wells are characterized by steep initial decline
rates but have long reserve lives. This means the average well produces gas
initially at a rate of about 3 MMcf/d and declines to less than 1 MMcf/d after
one year. The producing rate then declines at a much slower rate and the well
continues to produce for many years. Some of Anadarko's gas wells in the Bossier
play have tested at much higher initial rates than the average rate. These wells
initially produce at higher rates, decline rapidly, but recover more gas than
the average well.
In 2001, Anadarko continued drilling in the Bossier play at a brisk pace.
At the peak of activity in July 2001, the Company had a total of 32 rigs
drilling (26 in east Texas and six in north Louisiana). During 2002, the Company
expects to operate about 11 rigs in the play (six in east Texas and five in
north Louisiana). This decrease in activity reflects the Company's decision in
the second half of 2001 to focus on increasing its inventory of drilling
prospects by identifying new reserves through increased exploration, rather than
growing production during the current down cycle for energy prices.
In 2001, the Company drilled 175 wells, bringing the total Bossier play
well count to about 450 wells as of December 31, 2001. Of the wells drilled in
2001, 23 were exploratory wells of which 19 were successful. Bossier volumes for
2001 totaled 94 Bcf (net), or roughly 14% of the Company's total gas production,
making it Anadarko's largest onshore gas area. For 2002, the Company is planning
to drill 64 wells in the Bossier play. The Bossier exploratory program is
expected to be $56 million and total spending in the play is expected to be $170
million. Through its ongoing development and exploration programs, although
decreased at the present time, Anadarko continues to extend the limits of the
Bossier play.
Bossier-East Texas Anadarko has drilled over 400 Bossier wells in east Texas as
of the end of 2001. During the last half of 2001, activity was curtailed as
capital was shifted to other areas. Exploration, however, continued at a steady
pace to expand the play deeper into the basin and identify new field reserves.
As of year-end 2001, two wildcat wells were drilling and another three wells
were being completed. Anadarko continued to build its strong acreage position by
leasing an additional 88,000 acres throughout the year, giving Anadarko a total
of 283,000 net acres at year-end 2001.
Bossier-North Louisiana The Vernon field, acquired by Anadarko in 1999, was
producing 45 MMcf/d of gas (net) from 46 wells at the end of 2001 compared to 18
wells producing 5 MMcf/d of gas (net) in 1999.
Anadarko has extended the Vernon field in all directions through successful
exploration and development drilling in 2001. A total of 24 wells, seven of
which were exploratory, were drilled in 2001, more than doubling production. The
Ansley prospect was drilled immediately west of the Vernon field, significantly
expanding the area of known reserves. The well logged 125 feet of net pay and
subsequently tested 8 MMcf/d of gas in January 2002. The Hodde 28-1 well (100%
working interest (WI)) was completed at a rate of 11 MMcf/d of gas. This test
confirmed expansion of the field to the southwest.
Seismic, new depositional models and better fracture/stimulation technology
have been keys to growth in the Vernon field. Anadarko's position in the play
now totals over 99,000 net acres, an increase of 51,000 net acres from 2000.
Anadarko plans to drill 16 wells in 2002, which includes five exploration wells.
Carthage Anadarko's four rig infill drilling program in the Carthage area of
east Texas continued during 2001. The wells target primarily the tight gas sand
formations in the Cotton Valley interval. The application of a new fracture
stimulation technique has resulted in significantly better performance and
economics from these wells, with initial production rates averaging nearly 3
MMcf/d of gas from recent completions with many wells producing initial rates of
over 4 MMcf/d of gas. Prior techniques resulted in average initial rates of
6
2 MMcf/d of gas. Anadarko began to reduce activity in the Carthage area during
the last half of 2001, with a shift in capital to more long-term exploration.
For 2001, the multi-rig infill program in Panola, Henderson and Rusk counties of
Texas resulted in drilling a total of 34 wells aimed at the Cotton Valley
Formation.
In addition to the Cotton Valley interval, Anadarko also completed a number
of wells in shallower formations such as the Blossom. Anadarko utilizes a fleet
of about four workover rigs to help maintain production levels in the area. The
Company plans to drill two wells in the Carthage area in 2002.
South Louisiana During 2001, volumes from the more than 40 Anadarko-operated
wells on production in the area averaged 30 MMcf/d of gas and 6 MBbls/d of oil
and NGLs (net). The development drilling program in the Kent Bayou field (67%
WI) of Terrebonne Parish, Louisiana was a focal point of Anadarko's activities
in south Louisiana during 2001. The production facility was also upgraded. In
January 2002, two successful recompletions resulted in increasing production to
46 MMcf/d of gas and 10 MBbls/d of condensate (net).
CENTRAL TEXAS The Giddings field in Washington, Fayette, Lee, Brazos, Burleson
and Robertson counties of central Texas is the focal point of Anadarko's
horizontal drilling program targeting the Georgetown, Buda, Austin Chalk and
Glen Rose formations. During 2001, Anadarko continued to exploit these multiple
pay zones in central Texas. The Company's land holdings throughout central Texas
exceed 745,000 net acres, which are largely held by production. At year-end
2001, Anadarko had five rigs operating throughout its central Texas play: two in
the Georgetown; two in the Buda and Austin Chalk; and, one in the Glen Rose
formations. During 2001, net volumes from the Company's more than 1,600
producing wells throughout central Texas were nearly 196 MMcf/d of gas and more
than 14 MBbls/d of oil. In 2002, the Company expects to drill 41 development
wells and five exploration wells as part of a five-rig program. The Company has
budgeted approximately $82 million for these projects in 2002.
Buda/Austin Chalk The Company continued its successful redevelopment program of
the Buda and Austin Chalk formations in the Giddings field. During 2001, 57
wells were successfully re-entered to horizontally drill these formations. In
2001, production averaged 146 MMcf/d of gas and 14 MBbls/d of oil (net).
The cost to re-enter a well is about half the cost of drilling a new well.
The future potential for testing additional zones with horizontal laterals could
extend throughout Anadarko's Austin Chalk acreage holdings and 1,350 existing
wells operated by the Company.
Georgetown During 2001, Anadarko completed nine wells in the deep Giddings
over-pressured area. In 2001, production averaged 45 MMcf/d of gas (net) from
ten wells. The Company owns a 100% working interest in nine of the ten wells. A
separate intermediate-depth Georgetown play is being evaluated by the Company
using re-entries to minimize cost at this stage of exploration.
Glen Rose The new Glen Rose horizontal play continues to be expanded. In 2001,
production averaged 5 MMcf/d of gas (net) in the Mossy Grove field of Madison
and Walker counties, Texas. The Company drilled three wells (75% WI) in the area
during 2001.
East Chalk The Company's development program continued in the East Chalk, which
is located in southeast Texas and Louisiana. The Company holds 310,000 net acres
in the area. Total net production in the East Chalk during 2001 averaged 22
MMcf/d of gas and 6 MBbls/d of oil, condensate and NGLs. In the Brookeland field
of the East Chalk, six wells were completed in 2001.
PERMIAN BASIN Anadarko drilled 140 wells, performed 85 successful workovers and
recompletions, expanded two major waterfloods and installed one CO(2) flood in
the Permian basin during 2001. Net production for 2001 averaged 89 MMcf/d of gas
and 13 MBbls/d of oil, which resulted in cumulative net production of 10 MMBOE.
This compares to net production in 2000 of 12 MBbls/d of oil and 54 MMcf/d of
gas, which resulted in cumulative net production of 8 MMBOE. Anadarko has
interests in 389,000 gross (275,000 net) acres in the Permian basin and operates
approximately 5,400 wells.
7
In the Ozona field (65% WI), located in Crockett County, Texas, development
continued with the Company drilling and completing 96 wells and recompleting 50
wells during 2001. These operations added 35 MMcf/d of gas production, which
resulted in total field gas production of 94 MMcf/d of gas (gross). Anadarko
operates 1,900 wells in the Ozona field and plans to drill 30 new wells and
recomplete 40 wells in 2002.
Tertiary CO(2) flood operations in the San Andres reservoir of the
Slaughter field were implemented during 2001 at the H.T. Boyd lease (100% WI),
located in Cochran County, Texas. Although the Company has previously operated
CO(2) flood projects, this is the first to be installed by Anadarko.
Waterflood operations in the Clearfork reservoir in the TXL South Unit (67%
WI), located in Ector County, Texas, were expanded to cover the central and
southern portions of the unit. Water injection, which began in May of 2001, is
expected to increase production to 2 MBbls/d of oil (net) by year-end 2002.
A San Angelo/Clearfork waterflood development project continued throughout
2001 in the Snyder field (100% WI) located in Howard County, Texas. Anadarko
drilled six production and 12 injection wells during 2001. Anadarko has drilled
137 wells in the Snyder field on 2,300 acres acquired in 1998 and 1999.
MID-CONTINENT
Hugoton Embayment Anadarko's activities in the Hugoton Embayment, located in
southwest Kansas and the Oklahoma and Texas panhandles, are focused on the
deeper oil and gas zones below the shallow gas producing formations. Anadarko
controls 987,000 gross (913,000 net) acres in this area and operates about 2,700
wells. The deep drilling program in Kansas and the Oklahoma panhandle utilizes
3-D seismic technology to locate oil and gas bearing zones in the Morrow,
Chester and St. Louis formations. This multi-pay potential lowers the drilling
risk for the area. The average depth for a well in this area is 6,000 feet.
Anadarko currently owns or has license to 1,500 square miles of 3-D seismic in
the Hugoton Embayment and has drilled 144 successful deep wells based on this
data over the past seven years. Successful wells drilled in 2001 include the
Carpenter A-4, which had an initial production rate of 13 MMcf/d, and the Brown
L-1, which tested at a rate of 800 barrels per day (Bbls/d) of oil and 3 MMcf/d
of gas.
The Company's net production from the Hugoton Embayment area during 2001
was 183 MMcf/d of gas and 17 MBbls/d of oil, condensate and NGLs. Total net
volumes for 2001 were approximately 18 MMBOE (109 Bcf of gas equivalent). In
2001, the Company drilled 56 wells in the Hugoton Embayment. Anadarko also
recompleted 12 wells and carried out workover operations on 152 wells in the
area. In 2002, the Company has budgeted $20 million in the area and plans to
drill about 23 wells.
Texas Panhandle During 2001, the Company drilled one shallow well in the West
Panhandle Red Cave field in the Texas portion of the Hugoton Embayment. Anadarko
produced an average of 28 MMcf/d of gas (net) from 211 wells completed in the
Brown Dolomite or Red Cave formations in the West Panhandle field. This gas is
exceptionally rich in NGLs producing 40 barrels of NGLs per MMcf of gas in the
Red Cave wells and 145 barrels of NGLs per MMcf of gas in the Brown Dolomite
wells.
Central Oklahoma During 2001, net production from the 291 Golden Trend wells
operated by the Company was 20 MMcf/d of gas and 600 Bbls/d of oil. In the last
five years, Anadarko has drilled about 100 wells in the Golden Trend,
implemented a 40 acre infill drilling program and substantially increased its
leasehold position. In 2001, Anadarko drilled and completed 20 wells in the
Golden Trend. The play, located in Grady, Garvin and McClain counties of
Oklahoma, targets several different formations including deeper Sycamore,
Woodford, Hunton, Viola and Bromide. During 2001, rig activity steadily dropped
in the area as the Company re-evaluated play economics in light of falling gas
prices and high oilfield service costs. The abundant inventory of development
drilling locations will be revisited when market factors improve.
The Company's Golden Trend deep gas assets are complemented by the
Anadarko-operated Antioch Gathering System. The gathering system consists of 150
miles of pipe connecting over 280 wells and provides increased operational
control and market flexibility. During 2001, the Antioch system moved an average
of 25 MMcf/d of gas. In the area, Anadarko also operates five enhanced oil
recovery units, which produce from shallower horizons. The enhanced oil recovery
units are comprised mainly of CO(2) flood projects and produced 3 MBbls/d of oil
and 3 MMcf/d of gas in 2001. In 2002, the Company has budgeted $19 million in
the central Oklahoma area. The majority of this capital is planned for projects
within the enhanced recovery units.
8
WESTERN STATES
Overview Anadarko doubled its activity level in the western states area in 2001
and increased operated production by 21%, achieving major goals set following
the RME merger in 2000. The western states area primarily includes the Company's
oil and gas properties in the Land Grant area of Wyoming, Colorado and Utah. The
Land Grant was granted to a predecessor of RME by the federal government in the
mid-1800s. Economics on the Land Grant acreage are greatly enhanced by
Anadarko's fee mineral ownership position. For example, in a typical
outside-operated well on the Land Grant, Anadarko would have a 25% working
interest with a 33.75% net revenue interest, whereas for a comparable
outside-operated well outside the Land Grant, Anadarko would have a 25% working
interest with a 20% net revenue interest. The Company's operations in the Land
Grant are concentrated in the Green River basin and the Overthrust area.
The Company currently has approximately 8,751,000 gross (8,186,000 net)
acres, principally attributable to its Land Grant ownership. Anadarko and its
partners drilled over 300 wells in the area in 2001 compared to 160 wells in
2000, with an overall success rate of 96%. Of the total, 136 wells were
Company-operated, about double the 2000 activity. Anadarko's 2001 production
from the western states area averaged 287 MMcf/d of gas, 9 MBbls/d of oil and 14
MBbls/d of NGLs.
Anadarko plans to invest about $90 million in the western states area for
exploration and development in 2002. The Company's 2002 plans include drilling
212 development and 14 exploratory wells in Wyoming, Colorado and Utah.
Wyoming In the Green River basin of Wyoming, Anadarko-operated rigs focused on
conventional drilling projects in the Wamsutter and Brady areas. During 2001,
Anadarko operated from one to three rigs and had interests in up to 15
outside-operated rigs. In 2001, the Company drilled or participated in
approximately 160 wells in the Green River basin. In 2002, the Company plans to
drill 210 additional wells in this area.
Anadarko continued to exploit the Almond and Lewis formations within the
greater Wamsutter area, successfully extending production limits both to the
east and west. Anadarko participated in 98 Wamsutter area wells during 2001.
Anadarko's exploration efforts gained momentum during 2001. The Company
acquired over 415 square miles of 3-D and almost 350 miles of 2-D seismic data
for future exploration in the Green River basin, the Overthrust Belt and the
Hanna and Laramie basins before shutting down for winter range restrictions.
Utah Coalbed Methane During 2001, the Company drilled 18 wells in the Helper
and Drunkard's Wash fields in Utah. At year-end 2001, gross wellhead volumes
from Anadarko's coalbed methane wells in Utah were about 52 MMcf/d of gas and
are expected to increase by year-end 2002 as de-watering continues.
Wyoming Coalbed Methane The Company's Big George project in the Powder River
basin of Wyoming started in late 2001. At year-end, the project was producing 4
MMcf/d of gross wellhead gas, primarily from 20 wells. Gas production is
expected to increase as the additional 67 wells drilled in 2001 are brought
on-line and de-watered. The majority of construction required to bring the new
wells on-line was completed in 2001.
California Anadarko acquired leasehold interests in the San Joaquin Basin with
the Berkley acquisition during 2001. Anadarko has interests in 29,000 gross
acres in East Lost Hills and has 17,000 gross acres under option in Pyramid
Hills. During 2001, Anadarko took over operations on four wells. At year-end
2001, one well was producing, one well tested at 1.5 MMcf/d of gas (gross) and
was awaiting production facilities, one well was temporarily abandoned and one
well was still drilling. Two additional exploration wells were spud in late 2001
and are still drilling.
ALASKA
OVERVIEW Anadarko's activity in Alaska is concentrated primarily on the North
Slope. The Company also has interests in the Cook Inlet of south central Alaska.
During 2001, Anadarko participated in a total of 20 oil wells in Alaska with a
success rate of 100%. The Company had interests in 1,400,000 gross (481,000 net)
undeveloped lease acres, 32,000 gross (7,000 net) developed lease acres and
16,000 gross (8,000 net) fee acres in Alaska at year-end 2001. In addition, the
Company is finalizing agreements on leases covering 1,151,000 gross acres in the
Foothills area of the North Slope from Arctic Slope Regional Corporation under
an exclusive option-to-lease agreement, under which Anadarko also retains the
right to acquire leases on an
9
additional 1,941,000 acres. During 2001, Anadarko added to its significant
acreage position by participating in the North Slope/Beaufort Areawide 2001
lease sale. The Company, separately and in partnership with other companies,
submitted winning bids on 31 tracts covering 105,000 gross acres. The Company is
also waiting for final approval from a 2001 lease sale in the Foothills area for
207,000 gross acres. Combined, this gives the Company exploration access to
almost five million gross acres in Alaska.
NORTH SLOPE In November 2000, production began from the Alpine field (22% WI)
on Alaska's North Slope. The Alpine field produced an average of 88 MBbls/d of
oil in 2001. In the fourth quarter 2001, Alpine set field production records,
producing more than 108 MBbls/d of oil during a single day. With Alpine's
higher-than-expected production and new production anticipated from satellite
fields, the Alpine production facility will be further expanded to 135 MBbls/d
of capacity. The first phase of the expansion should be completed mid-2003. As
of year-end 2001, 49 wells -- 27 production wells and 22 injection or service
wells -- have been completed. The entire Alpine development program will have
more than 100 horizontal wells from two drill sites. During the fourth quarter
of 2001, construction was finished at Colville Delta 2, the drill site used to
develop the western part of the field, and oil production from that portion of
the field began.
The Alpine field, which represents the nation's largest onshore oil
discovery in more than a decade, serves as an excellent example of commitment to
minimizing the environmental impact of exploration and production operations in
sensitive areas. The production facilities for the field are situated on about
100 acres, roughly one-third of one percent of the subsurface reservoir area
being developed. In addition, Alpine is a zero discharge facility; the waste
generated is reused, recycled or disposed of properly. There is no permanent
road to the field; therefore, ice roads, which leave no trace on the tundra, are
utilized during the winter. Equipment, supplies and personnel are transported by
small aircraft year-round.
In 2001, Anadarko and its partner announced the Nanuq discovery, a
satellite oil field about four miles south of the Alpine field. The Nanuq
accumulation is the second satellite field to be discovered near Alpine. The
first satellite field, the Fiord, was announced as a discovery in 1999. Both the
Nanuq and Fiord satellites (22% WI) will be developed and produced through the
expanded Alpine facility beginning in the 2005-2006 time frame, filling in the
natural production decline of Alpine.
During 2001, Anadarko and its partner announced first discoveries in the
National Petroleum Reserve-Alaska (NPR-A). During the past two winter drilling
seasons, five wells and one sidetrack well, which targeted the Alpine producing
horizon, encountered oil and gas and condensate. These are the Spark #1, Spark
#1A, Moose's Tooth C, Lookout #1, Rendezvous A and Rendezvous #2 (22% WI). An
additional well, that was drilled in 2000, was a dry hole. These
outside-operated discoveries are located from 15 to 25 miles southwest of the
Alpine field.
Anadarko expects to drill its first operated wildcat on the North Slope in
2002. The exploration well is the Altamura #1 (100% WI), located in the NPR-A
just south of the Moose's Tooth discovery. In addition, the Company plans to
participate in the acquisition of 1,300 square miles of 3-D seismic and 600
miles of 2-D seismic and continue the Company-operated Foothills exploration
program. The Company also expects to participate in up to seven additional
exploration wells with partners, including delineation of last year's
discoveries at Moose's Tooth. Warm weather in the 2001-2002 season has delayed
access to the North Slope and some drilling may be postponed due to schedule
limitations.
COOK INLET In 1999, Anadarko completed a long-term test to confirm the
potential commerciality of its discovery at the Lone Creek No. 1 well (50% WI)
on the Moquawkie prospect. In 2001, the Company and its partner began securing
the necessary permits and agreements to develop this discovery. Anadarko holds
approximately 56,000 gross lease acres in the Moquawkie area. The Company does
not plan significant capital expenditures for 2002 in the Cook Inlet.
GULF OF MEXICO
OVERVIEW In 2001, Anadarko significantly expanded its presence in the Gulf of
Mexico, particularly in exploration lease blocks in deepwater for both sub-salt
and conventional drilling. At year-end 2001, about 7% of the Company's proved
reserves were located offshore in the Gulf of Mexico. Net production volumes in
2001 from these properties averaged 329 MMcf/d of gas and 24 MBbls/d of oil,
condensate and NGLs. At
10
[OFFSHORE MAP]
<Table>
<Caption>
NET NET NET
DEVELOPED UNDEVELOPED PRODUCING
ACRES ACRES WELLS
--------- ----------- ---------
OFFSHORE:
United States
California................................................ -- 2,785 --
Florida................................................... -- 42,710 --
Louisiana*................................................ 182,456 380,331 157
Mississippi*.............................................. 3,996 165,784 --
Texas*.................................................... 33,209 300,840 49
* Drilling activities were conducted in these areas in 2001.
</Table>
11
year-end 2001, Anadarko owned an average 64% interest in 337 blocks representing
483,000 gross (220,000 net) acres in developed properties and 1,215,000 gross
(890,000 net) acres in undeveloped properties in the Gulf of Mexico. Anadarko
also holds options to earn working interests covering an additional 110 blocks.
During 2001, Anadarko participated in 19 wells in the Gulf of Mexico: 12 shelf
conventional, four sub-salt and three deepwater wells. Drilling results in the
Gulf of Mexico included 11 gas wells, two oil wells and six dry holes for a
success rate of 68%. Throughout the Gulf of Mexico, Anadarko has budgeted about
$370 million for capital spending, which includes drilling 20 wells in 2002.
SHELF CONVENTIONAL Shallow water projects in the Gulf of Mexico continue as the
Company exploits the potential around several of its larger and more mature
fields. Ongoing re-mapping and re-processing have generated numerous prospects,
adding to the Company's large inventory of projects identified from extensive
field studies. During 2001, nine discoveries were made. Workovers and
recompletions were performed on several wells at the South Marsh Island (SMI)
281, Eugene Island 87 and SMI 268 fields.
Activity in 2001 was highlighted by the Company's continued success at SMI
280/281 (50% WI). Discovered in 1973, this is one of Anadarko's more mature
offshore fields, but one that holds significant exploitation and deep
exploration potential. During 2001, the SMI 280 #6 and SMI 280 #7 wells logged
267 and 254 feet of net pay, respectively. The SMI 280 #6 and #7 wells are
expected to be flowing in the second quarter of 2002 at between 75 and 100
MMcf/d of gas production (gross). The Company has finished drilling the SMI 281
#8, #9 and #10 wells. Combined, these five wells are expected to add an
additional 150 MMcf/d of gross gas production by year-end 2002.
Shallow water projects will continue to be an important part of Anadarko's
Gulf of Mexico program. Anadarko has interests in a total of 110 blocks in its
shelf program, with 45 prospects identified. In 2002, the Company is planning to
drill nine development and nine exploratory wells near its older existing
fields.
SUB-SALT During 2001, production continued from the Hickory (Grand Isle
110/111/116) and Tanzanite (Eugene Island 346) sub-salt fields discovered in
1998 off the coast of Louisiana. Currently, the Hickory field has three
producing wells and Tanzanite has two producing wells. The Tanzanite field (100%
WI) had total net production of 4 MMBbls of oil and 23 Bcf of natural gas in
2001. The Hickory field (50% WI) had total net production of 2 MMBbls of oil and
25 Bcf of natural gas in 2001.
At the end of 2001, the Company made a discovery with the Pardner well
(100% WI), located on Mississippi Canyon 400/401 in about 1,200 feet of water.
The well, drilled to a depth of 8,200 feet, encountered 92 net feet of oil pay
in four intervals. The Company plans to sub-sea tie back the well and to bring
it on-line in 2003.
During 2001, a sub-salt exploration well at the Tarantula prospect (100%
WI), located on South Timbalier 308 in 480 feet of water, encountered about 170
feet of net pay. The #2 confirmation well was drilled and encountered 153 feet
of net pay in five zones. A third well is being planned to optimize future
development plans for Tarantula.
The Sazerac well (100% WI), a prospect located on Green Canyon Block 99,
reached total depth at 16,700 feet in the down-dip sidetrack well. The well
encountered some modest pay intervals in both the sidetrack and original
wellbore. The Company believes that not enough pay is present to make this
project economic.
The Eiger Sanction well (100% WI) is located on Mississippi Canyon Block
667 in 2,950 feet of water at the north end of the Gomez deepwater discovery.
The original well and sidetracks reached a total depth of 25,900 feet in March
2002 and has encountered two potential pay intervals that were penetrated
between 22,000 and 23,500 feet. They are not currently considered sufficient to
economically develop. Further data evaluation will be ongoing in 2002 to
determine future activity.
The Thunder well (30% WI), which is located on Eugene Island 341, was
spudded in mid-December 2001 and is being drilled to a proposed depth of 20,000
feet. The well, located in 300 feet of water, is outside-operated and is
expected to take 90 days to reach the total depth.
Anadarko has interests in a total of 122 blocks in its sub-salt program,
with 19 prospects identified. An additional 20 blocks could be earned within its
option program. One exploratory well and one development well are planned in the
sub-salt for 2002. To date, eight of Anadarko's 16 sub-salt projects have
resulted in discoveries. Four of these discoveries are commercial and already on
production.
12
DEEPWATER Marco Polo (100% WI), Anadarko's first deepwater development project,
is located on Green Canyon Block 608 about 150 miles offshore Louisiana in the
Gulf of Mexico. Anadarko made the Marco Polo discovery in 2000 and has drilled a
total of two wells and four sidetracks, which encountered between 90 and 360
feet of net oil and gas pay. Recently, the Company acquired the rights to
explore and develop eight blocks in the Green Canyon area adjacent to the Marco
Polo discovery. Anadarko plans to drill up to five wells on the complex of 11
blocks in 2002.
In December 2001, Anadarko signed a letter of intent with El Paso Energy
Partners (EPN) under which a floating production platform capable of
accommodating production from multiple fields, including production from Marco
Polo, will be installed by EPN. The floating production platform will be
stationed in 4,300 feet of water and will function as a hub. EPN and Cal Dive
International, Inc. will own the platform and Anadarko will be the operator.
Production capacity will be 100 MBbls/d of oil and 250 MMcf/d of gas. Under the
proposed agreement, Anadarko will have firm capacity of 50 MBbls/d of oil and
150 MMcf/d of gas. The remainder of the platform capacity will be available to
Anadarko for additional production and to third-parties who have fields
developed in the area. Oil and gas processed on the platform will be transported
through new gathering pipelines owned by EPN to downstream markets. The oil will
be transported through a new 34-mile pipeline to the Ship Shoal 332 platform
where onshore markets can be accessed. EPN intends to build a gas pipeline from
the Marco Polo platform to Green Canyon Block 236 where onshore markets can be
accessed.
The Company continued its deepwater exploration program in 2001. The Blues
Image well (50% WI), located on Mississippi Canyon 587, had a proposed depth of
24,000 feet. The operator suspended operations at a depth of 15,000 feet due to
a drilling problem. Anadarko is working with the operator on plans to resume
drilling during 2002. The White Ash prospect (100% WI), located on Mississippi
Canyon Block 392 in nearly 7,300 feet of water, was drilled to gain information
prior to Anadarko going to a lease sale. The well reached a total depth of
18,225 feet and was a dry hole, but provided useful information to adjust the
Company's bidding strategy. The Lisa Anne exploratory well (100% WI), located on
Green Canyon Block 474, was recently drilled to a depth of 13,279 feet, but was
unsuccessful.
Anadarko holds a total of 105 lease blocks in its deepwater program and has
identified 29 prospects. An additional 98 blocks could be earned within its
option program. During 2001, the Company significantly increased its exploration
acreage in the deepwater through the South Auger Participation Agreement and
success at lease sales.
South Auger Participation Agreement During 2001, Anadarko entered into a
Participation Agreement with BP to explore 95 deepwater blocks held by BP in the
Garden Banks and Keathley Canyon areas of the western Gulf of Mexico. The 95
blocks, held 100% by BP, are within a larger 640-block area of mutual interest
where the two companies will license and reprocess 3-D seismic data. These
blocks are in water depths ranging from 3,000 to 6,000 feet. The agreement gives
Anadarko the option to earn a 33% to 66% working interest in the blocks.
Anadarko will fund 100% of the licensing and re-processing costs and pay a
disproportionately larger share of the first four wells drilled. Also, as part
of the agreement, BP assigned Anadarko its rights in eight blocks in the Green
Canyon area near the Company's Marco Polo discovery.
Lease Sales Anadarko participated in the OCS Federal Lease Sale 178 held in
March 2001 and acquired 23 tracts covering 120,000 acres in the Gulf of Mexico.
The blocks, which represent an investment of $32 million for Anadarko, include
seven blocks on the Outer Continental Shelf in shallow water and 16 blocks in
deepwater.
Anadarko also acquired 26 tracts (100% WI) in the Western Gulf of Mexico
Lease Sale 180 held in August 2001. The Company's total investment was about $6
million. The tracts cover more than 133,000 acres in deepwater, mainly around
the Port Isabel and Alaminos Canyon areas.
In January 2002, Anadarko acquired 26 tracts (100% WI) in the Eastern Gulf
of Mexico Lease Sale 181. The Company's total investment was about $136 million.
The 26 tracts cover nearly 150,000 acres in water depths ranging from 7,000 to
9,500 feet. The blocks included in Sale 181 have not been available for
exploration since 1988, long before major advancements occurred in seismic
imagery and deepwater drilling and development technology. Mapped prospects on
these blocks may potentially hold substantial oil and gas reserves. The Company
is considering taking on partners to recover lease costs and reduce risk.
Exploration drilling is expected to take place in 2003.
13
GAS PROCESSING
The Company processes gas at various third-party plants under agreements
generally structured to provide for the extraction and sale of NGLs in efficient
plants with flexible commitments. The Company has agreements with four plants in
the western states area, 14 plants in the mid-continent area and 10 plants in
the gulf coast area. Anadarko also processes gas and has interests in one
Company-operated plant and three non-operated plants in the western states.
Anadarko's strategy to aggregate gas through Company-owned and third-party
gathering systems allows Anadarko to secure processing arrangements in each of
the regions where the Company has significant production.
PROPERTIES AND ACTIVITIES -- CANADA
OVERVIEW Anadarko's Canadian operations were acquired in July 2000 with the RME
merger transaction and further expanded in March 2001 with the purchase of
Canadian-based Berkley Petroleum Corp. The Berkley acquisition increased
Anadarko's Canadian reserves by 42% and total acreage position from three
million to nearly five million net acres. Since the Berkley acquisition,
Anadarko has added an additional 550,000 acres for a net total of 5,262,000
acres.
Anadarko has operations in Alberta, northeast British Columbia,
Saskatchewan and the Northwest Territories of Canada. The Company has proved
reserves in Canada of 315 MMBOE, which includes 1.2 Tcf of gas and 108 MMBbls of
crude oil, condensate and NGLs. In 2001, net production from the Company's
properties in Canada averaged 331 MMcf/d of gas and 38 MBbls/d of crude oil,
condensate and NGLs, or 17% of the Company's total production volumes.
At year-end 2001, Anadarko had 22 rigs under contract and seven
Company-operated exploratory wells plus five non-operated wildcat wells were
drilling. Anadarko reached a peak of 25 rigs drilling in Canada in the 2001-2002
winter season. During 2001, Anadarko participated in 476 wells with a 94%
success rate, including 285 gas wells and 162 oil wells. Anadarko has 9,102,000
gross (3,554,000 net) undeveloped lease acres, 1,942,000 gross (1,118,000 net)
developed lease acres and 590,000 gross (590,000 net) fee acres in Canada. The
Company's 2002 oil and gas capital budget of $255 million for Canada includes
approximately $190 million for development drilling and infrastructure projects
that are expected to increase production primarily in northeast British Columbia
and northern Alberta. The budget also includes $65 million for exploration which
will include drilling approximately 50 exploration wells. The accompanying map
illustrates the Company's developed, undeveloped and fee acreage, number of
productive wells and other data relevant to its properties in Canada.
NORTHWEST TERRITORIES In the Mackenzie Delta, Anadarko and its partners
conducted a 2-D seismic survey of approximately 620 miles in early 2001.
Acquisition of a 130 square mile 3-D seismic program over this block commenced
in January 2002. The Company holds about 400,000 net acres in the Mackenzie
Delta/Beaufort Sea region.
In the southern territories, Anadarko completed a deal in 2001 to explore
on several exploration licenses in the Fort Liard sub-basin. Under the
agreement, Anadarko will acquire 3-D and 2-D seismic in the 2001-2002 winter
season and drill a test well the following year with the potential to earn an
interest, via rolling options, in up to 71,000 acres. The seismic programs are
expected to be completed by the end of March 2002. Additionally in Fort Liard,
two Bovie Slave Point wildcat wells (50% WI) spudded in late 2001 and reached
total depth in early 2002. Both wells are pending completion. A third Slave
Point exploratory well (100% WI) will begin drilling in early 2002.
BRITISH COLUMBIA In 2001, Anadarko drilled, completed and tied-in the Altares
C-15-I exploration well (100% WI). This Mississippian formation well came
on-line at 5 MMcf/d of gas. Six follow-up leads have been identified. The first
of two exploratory wells spudded in December 2001 on a similar play concept to
the initial discovery. The well is expected to reach total depth by the end of
the first quarter 2002. The Company will evaluate seismic over 24 sections
(15,300 acres) and then drill a test well to earn an interest in eight sections
and a similar option on the remaining acreage. Another exploration well, the
Green A-55-A (100% WI), was drilled in the Buckinghorse prospect area in 2001
and flowed at a rate of 4 MMcf/d of gas.
14
[CANADA MAP]
<Table>
<Caption>
NET NET NET NET
DEVELOPED UNDEVELOPED FEE PRODUCING
ACRES ACRES ACRES WELLS
--------- ----------- ------- ---------
CANADA:
Alberta*.................................... 651,472 1,159,601 505,526 2,535
British Columbia*........................... 182,553 817,676 -- 346
Northwest Territories....................... 1,093 1,205,002 -- 1
Saskatchewan*............................... 282,756 139,249 84,133 1,833
Scotian Shelf............................... -- 231,975 -- --
OFFICE LOCATIONS:
Canada
Calgary, Alberta
Elk Point, Alberta
Fort St. John, British Columbia
Medicine Hat, Alberta
Peace River, Alberta
</Table>
- ---------------
* Drilling activities were conducted in these areas in 2001.
15
Additional drilling and tie-in activity in northeast British Columbia took
place in the Graham/Chowade field (60% WI) during 2001. Compression was also
added in the field resulting in 5 MMcf/d of incremental gas production to a
total of 27 MMcf/d of gas.
In the Sukunka area of the British Columbia Foothills, Anadarko is
participating in a high impact exploratory well (30% WI), which is a 15,000 foot
deep Mississippian test. Well results are expected by the end of the second
quarter 2002.
In Anadarko's Jean Marie play in northeast British Columbia, the Company
increased its acreage position by over 100,000 acres to approximately 200,000
net acres in 2001. In 2001, the Company completed a total of nine horizontal
wells at a combined initial production rate of 6 MMcf/d of gas.
ALBERTA In northwest Alberta, two successful Slave Point oil wells were
drilled, offsetting the Dawson 13-2 well (90% WI), a Slave Point new pool
discovery which tested 1,138 Bbls/d of oil. The Dawson 3-11 (90% WI) and Dawson
11-11 (90% WI) tested at a rate of 1,200 Bbls/d and 530 Bbls/d of oil,
respectively. Additionally, in a separate pool, two Dawson field development
wells were completed. The Dawson 8-8 tested at a rate of 1,200 Bbls/d of oil and
the Dawson 16-7 tested at a rate of 1,800 Bbls/d of oil. Anadarko plans to drill
an additional 30 wells in the Dawson area in 2002.
In the Saddle Hills area of northern Alberta, the 15-28 discovery well
(100% WI) tested 6 MMcf/d of gas and is expected to begin producing in the first
quarter of 2002. Based on this exploration success, Anadarko plans to drill
three offset wells in 2002 and pursue similar exploration opportunities.
In north central Alberta, in the Wild Hay area, up to five rigs were active
during the fourth quarter of 2001. In this deep basin gas play with multi-pay
potential, Anadarko achieved a 100% success rate for 2001 in a 27 well program.
Anadarko also completed a 30 MMcf/d of gas expansion of the Wild Hay Gas
Plant (100% WI) late in 2001, increasing total capacity to 53 MMcf/d of gas.
Activity continued in Anadarko's heavy oil area in northeast Alberta where
123 wells were drilled and 101 wells were recompleted. Production averaged 20
MBbls/d of oil (net) during 2001.
SASKATCHEWAN The Company drilled and completed 215 wells and recompleted 87
wells in the Hatton shallow gas play in southwest Saskatchewan during 2001,
adding 12 MMcf/d of net gas production. The Company expects to drill about 100
wells in 2002.
In southeast Saskatchewan, two high volume horizontal oil wells in the
Steelman pool tested 2 MBbls/d of oil and 800 Bbls/d of oil respectively, from
the Devonian Winnipegosis formation. Two additional horizontal wells are planned
for the Steelman area in the first quarter of 2002.
PROPERTIES AND ACTIVITIES -- ALGERIA
OVERVIEW Anadarko is actively developing oil fields discovered by the Company
in Algeria's Sahara Desert. Since 1989, Anadarko has participated in 79
productive wells (12 exploration and 67 delineation/development) and has
submitted detailed development plans (called Commerciality Reports) for 12
fields in Algeria. The Company has proved reserves in Algeria of 387 MMBbls of
crude oil as of year-end 2001. Activity in 2001 was highlighted by significant
development progress with the addition of 150 MBbls/d of production capacity, as
well as Anadarko's return to exploration in Algeria. In 2001, Anadarko
participated in 19 wells with a success rate of 95% -- 18 oil wells and one
unsuccessful well. Anadarko plans to invest about $160 million in Algeria in
2002. At the end of 2001, the Company had 3,596,000 gross (1,226,000 net) acres
in Algeria. The accompanying map illustrates the Company's developed and
undeveloped acreage, number of productive wells and other data relevant to its
properties in Algeria.
CONTRACTS/PARTNERS Anadarko's interest in the original production sharing
agreement (PSA) is 50% before participation at the exploitation stage by
SONATRACH, the national oil and gas enterprise of Algeria. The Company has two
partners, each with a 25% interest in the Algerian venture, also prior to
participation by SONATRACH; they are LASMO Oil (Algeria) Limited, a wholly-owned
subsidiary of ENI-Agip, and Maersk Olie Algeriet AS, a wholly-owned subsidiary
of Maersk Olie Og Gas AS, a company in the Danish A.P. Moller group. Under the
terms of the PSA, oil reserves that are discovered, developed and produced will
16
[ALGERIAN PROPERTIES MAP]
Undeveloped Acreage --
Total 3.4 million acres (1.2 million acres net)
Developed Acreage (HBNS, HBN, ORD, HBNSE, BKNE, RBK, QBN & BKE fields) --
Total 209,000 acres (51,000 acres net)
Productive Wells --
Total 79 (20 net)
Fields discovered to date shown graphically
HBN field*
HBNS field*
HBNSE field*
RBK field
QBN field
BKNE field*
BKE field
ORD field*
EKT field
EMN field
EMK field
EME field
Blocks shown graphically
404*
406b
208
211
- ---------------
*Drilling activities were conducted in these areas in 2001.
17
be shared by SONATRACH, Anadarko and its two partners. Anadarko and its partners
funded SONATRACH'S 51% share of exploration costs and are entitled to recover
these exploration costs out of production in the exploitation phase. As of
year-end 2001, Anadarko and its partners had recovered about 44% of SONATRACH'S
portion of exploration costs through an increased share of production of
cost-recovery oil with the majority of the remaining 56% expected to be
recovered by early 2003. SONATRACH is responsible for 51% of development and
production costs. During 2000, SONATRACH and Anadarko formed a non-profit
company, Groupement Berkine, to carry out their joint operating activities under
the PSA. SONATRACH and Anadarko fund the expenditures incurred by Groupement
Berkine according to their participating interests under the PSA. SONATRACH has
owned shares of the Company's common stock since 1986 and at year-end 2001 was
the beneficial owner of 5% of Anadarko's outstanding common stock.
In 2001, Anadarko and its partners signed an amendment to the PSA with
SONATRACH, which allows exploration to resume on Blocks 404, 208 and 211. The
exploration phase of the original PSA ended in 1998. While the terms of the
amendment are not as favorable as the terms of the original agreement, the
Company still considers the terms attractive. The Company also signed a separate
exploration license, in which Anadarko has a 100% interest, for Block 406b at
Algeria's licensing round in 2001.
DEVELOPMENT First oil production began in May 1998, from facilities at the
Hassi Berkine South (HBNS) field. Production from a second processing unit for
the HBNS field began in August 2001. Oil produced from the HBNS field is sold as
Saharan Blend, a high quality crude that provides refiners with large quantities
of premium products such as jet and diesel fuel. Production from the HBNS field
averaged 77 MBbls/d of oil (gross) in 2001 compared to 68 MBbls/d of oil (gross)
in 2000.
SONATRACH and Anadarko are developing the Hassi Berkine (HBN) field just
north of the HBNS field. A crude oil production train with the capacity to
process 75 MBbls/d of oil, as well as a gathering system, injection lines and
facilities for crude oil storage and export have all been installed as part of
the facility expansion. Production from this third processing unit began on
December 23, 2001 -- two months ahead of schedule. Having the HBN field on-line
increases the nominal oil production capacity of the central processing facility
to 210 MBbls/d. The HBN field is located across Block 404 and Block 403 and will
be unitized between two associations. Development costs and production sharing
will be 74.5% for the Anadarko/SONATRACH Association on a preliminary basis.
This percentage is subject to future redetermination.
A fourth production train, currently under construction at the HBNS
complex, will process production from the Block 404 satellite fields -- Hassi
Berkine South East (HBNSE), Rhourde Berkine (RBK), Qoubba North (QBN), Berkine
Northeast (BKNE) and Berkine East (BKE). First production from this fourth unit
is expected in the second quarter of 2002 and should increase total oil
production capacity by an additional 75 MBbls/d to 285 MBbls/d of oil.
Anadarko is also actively involved in developing the Ourhoud (ORD) field.
The facilities for this field will have a capacity of 230 MBbls/d of oil (gross)
when completed. Production from the first train is expected in early 2003. The
contract calls for the construction of three oil production trains, as well as
water injection and gas processing and injection facilities, a field gathering
system and crude oil storage and shipping installations.
Located in the southern portion of Block 404, the ORD field extends into
Block 406a and Block 405 and consequently will be unitized with the companies in
those Blocks. The preliminary allocation of development and production costs to
the Anadarko/SONATRACH Association on Block 404 is 37.5%. This percentage is
subject to future redetermination. Anadarko, Maersk, Lasmo, Cepsa, Burlington
Resources and Talisman Energy are participating in development work on the field
in partnership with SONATRACH. To date, a total of 19 productive development
wells have been drilled in the ORD field and development drilling will continue
in 2002.
Anadarko also has several fields further south on Block 208; these include
the El Merk field (EMK), the El Kheit Et Tessekha field (EKT), the El Merk East
field (EME) and the El Merk North field (EMN). Initial development plans for
these more recent discoveries were submitted in 1998 and are being finalized.
Design work has begun, and these production facilities are expected to be built
in the future.
EXPLORATION The PSA, as amended in 2001, allows Anadarko and its partners to
resume exploration on the three blocks outside of the exploitation license
boundaries encompassing the previous discoveries. These are
18
the same blocks Anadarko and its partners began exploring in 1989 and the new
agreement allows Anadarko to build on the knowledge gathered since then using
current state-of-the-art technology to commence a new phase of exploration.
Under the terms of the three-phase exploration program, Anadarko and its
partners will spend a minimum of $55 million. During the first five years, 400
square kilometers of 3-D seismic and 1,100 kilometers of 2-D seismic will be
acquired and processed; the results of previous seismic surveys will be
reprocessed; and six exploration wells will be drilled. Work has commenced on
reprocessing the existing 2-D seismic database and acquisition is underway for
1,100 kilometers of new 2-D seismic. Exploration drilling is expected to begin
during 2002. Should the sixth- and seventh-year options be exercised, an
additional exploration well will be drilled in each year. Anadarko and its
partners will finance 100% of the exploration investment and SONATRACH will
participate 51% in the development and exploitation phases of any discoveries.
Where appropriate, existing facilities and infrastructure may be used to develop
any discoveries, thereby reducing development costs and potentially accelerating
first oil production.
The license for Block 406b has a three-year initial term. A work program
commitment includes seismic acquisition and one exploration well. Anadarko has a
100% interest in this 686,000 acre block, which is located in the Berkine basin
to the east of Anadarko's other license areas. The Company now controls a total
of 3,596,000 acres in this region of the Sahara.
Political unrest continues in Algeria. Anadarko is closely monitoring the
situation and has taken reasonable and prudent steps to ensure the safety of
employees and the security of its facilities in the remote regions of the Sahara
Desert. Anadarko is presently unable to predict with certainty any effect the
current situation may have on activity planned for 2002 and beyond. However, the
situation has not had any material effect to date on the Company's operations.
See Regulatory Matters and Additional Factors Affecting Business -- Foreign
Operations Risk under Item 7 of this Form 10-K.
PROPERTIES AND ACTIVITIES -- OTHER INTERNATIONAL
OVERVIEW The Company's other international oil and gas production and
development operations are located primarily in Venezuela, Qatar and Oman. The
Company also has less significant international oil and gas operation
activities, including interests in two non-operated offshore producing
properties in Australia and a producing interest in a non-operated property in
Egypt. The Company currently has exploration projects in Tunisia, the Middle
East, West Africa, Australia, the Faroe Islands, off the coast of Georgia in the
Black Sea and other selected areas.
The Company has total proved reserves in these other international
locations of 164 MMBbls of crude oil, condensate and NGLs and 146 Bcf of gas at
year-end 2001. During 2001, net production from the Company's other
international properties was 4 MMcf/d of gas and 36 MBbls/d of crude oil,
condensate and NGLs, or 7% of the Company's total production volumes. Anadarko
participated in a total of 31 wells in its other international locations during
2001 with a success rate of 84%. Drilling results included 25 oil wells, one gas
well and five dry holes. Anadarko has 29,981,000 gross (15,314,000 net)
undeveloped lease acres and 427,000 gross (87,000 net) developed lease acres in
these international areas. See Regulatory Matters and Additional Factors
Affecting Business -- Foreign Operations Risk under Item 7 of this Form 10-K.
VENEZUELA The Company's Venezuelan operation was acquired with the RME merger
and consists of the Oritupano-Leona concession, which is a risk service
contract. The Oritupano-Leona Block, in which the Company has a 45%
participating interest, covers 395,000 acres and had approximately 276 producing
wells at year-end 2001. Oil production from the block reached a record level of
53 MBbls/d of oil in December 2001 and averaged 48 MBbls/d of oil (22 MBbls/d
net) during 2001. For 2001, net production volumes totaled 8 MMBOE. The active
development/exploitation program in 2001 included 19 new well completions and 50
well reactivations. The operator and Anadarko are finalizing plans for a reduced
drilling program in 2002 due to current economic and industry conditions.
MIDDLE EAST During 2001, the Company acquired Gulfstream Resources Canada Ltd.
for a total value of $118 million plus the assumption of $10 million of debt.
Anadarko believes the Gulfstream assets, concentrated in Qatar and Oman, have
production growth opportunities and exploration upside.
19
Qatar Anadarko has a 65% interest in the Al Rayyan field, which is part of an
Exploration and Production Sharing Agreement covering offshore Qatar Blocks 12
and 13. Production from the Al Rayyan field, located on offshore Block 12,
averaged 4 MBbls/d of oil net during the fourth quarter of 2001. A redevelopment
program, which includes increasing existing facility capacity and drilling
horizontal wells, is underway and production is expected to increase to 35
MBbls/d of oil (13 MBbls/d net) in early 2003. A six-leg jack-up rig was
purchased and the decks were cleared for conversion to a permanent production
facility with the capacity of 45 MBbls/d of oil. Approximately $80 million is
budgeted in 2002 for construction of production facilities, development drilling
in the Al Rayyan field, and an exploration well on Block 12. Block 13, was
removed from a force majeure status as the result of a boundary settlement
between Qatar and Bahrain in March 2001. During 2002, the Company plans to
initiate geological and geophysical technical work on Block 13.
Anadarko also has a 49% interest in an exploration and production sharing
agreement covering offshore Block 11. Two exploratory wells drilled on Block 11
during 2001 found the objective wet and have been plugged and abandoned.
Evaluation is underway to determine the potential for any further exploratory
work on Block 11.
Oman Anadarko, the operator, drilled a horizontal step-out well in the Hafar
field in Block 30 during 2001. Evaluation of well tests is currently being
conducted. One existing well on the block was re-entered and flow tested during
the fourth quarter of 2001. The development plans will be finalized based on the
results of the well tests. Anadarko has a 100% interest in the field. Gas
production will be sold to the Oman government under a long-term sale agreement.
EGYPT Anadarko has a 25% non-operated interest in a producing field offshore
Egypt named Zaafarana. Average net sales volumes for 2001 were 950 Bbls/d of
oil.
BRAZIL Anadarko is the operator and has a 90% interest in the SES 107 Block,
which was acquired with the RME merger. In 2001, Anadarko relinquished its
acreage in the BT Seal 101 Block.
AUSTRALIA Anadarko has a 15% interest in outside-operated production facilities
in the Jabiru and Challis fields. The Company's net sales volumes from the
Jabiru and Challis fields during 2001 were 356 MBbls of oil. Anadarko also has
agreements on three licenses (AC/P 25, 26 and 27) in the Timor Sea, Northwest
Shelf of Australia. Anadarko drilled one well on each license area in the first
quarter of 2002, all of which were unsuccessful.
TUNISIA The Company has a 47% interest and is the operator of the 1.1 million
acre Anaguid block in the Ghadames basin of Tunisia, which will revert to a 24%
interest if ETAP (Tunisia's national oil company) exercises its option to back
into the project. The acreage is on trend with the Company's discoveries in
Algeria to the west and it holds the potential for the discovery of Triassic and
Silurian oil fields. In 2001, the first of two available extension periods was
granted, allowing time for the integration of the most recent seismic surveys,
in preparation for the forthcoming exploration drilling program.
Just south of the Anaguid permit, Anadarko holds a 50% interest in the
Jenein Nord block prior to back-in by ETAP. During 2001, two 2-D seismic surveys
were acquired in the southeast and northern areas of the permit.
In 2000, Anadarko negotiated an option to explore the Sanrhar concession,
which is surrounded by the Anaguid permit. In 2001, as part of the Anaguid
seismic program, additional seismic data was acquired in Sanrhar.
In 2002, Anadarko will further evaluate the most recently acquired seismic
surveys to finalize the prospect inventory ahead of a forthcoming exploration
drilling program.
WEST AFRICA Anadarko operates the Marine IX Block offshore the Republic of
Congo with a 47% interest. Anadarko and partners have approved and scheduled the
drilling of the Rita prospect on this block. Rita is an amplitude-supported
prospect with significant reserve potential. The Company expects to spud the
well, located in 4,400 feet of water, during the second quarter of 2002.
Anadarko is also the operator and holds a 50% interest in the Agali Block
offshore Gabon. 3-D seismic data, acquired in 2001, will be processed and
evaluated during 2002. Drilling is not expected to occur until 2003.
NORTH ATLANTIC MARGIN In the Faroe Islands, Anadarko is the operator and sole
licensee of License 007 and holds a 28% interest in the outside-operated License
006. The licenses cover a total of 618,000 acres. In 2001,
20
Anadarko operated and participated in both a conventional long-offset seismic
program and a sub-basalt seismic imaging trial survey. The Company also acquired
a proprietary seismic survey and participated in a marine magnetotellurics
program. In 2002, the Company plans to fully integrate this data as part of a
comprehensive license and basin evaluation.
In 2001, Anadarko participated in an unsuccessful exploration well in
Tranche 21 (20%), located west of Britain on the United Kingdom Continental
Shelf (UKCS). The first exploration periods for UKCS Tranches 21, 61 and 63,
where the Company's interests are 20%, 8% and 50%, respectively, are due to
expire in April 2002. Certain acreage in Tranche 61 is expected to be retained.
GEORGIA -- BLACK SEA Anadarko has a Production Sharing Contract with the State
of Georgia. The agreement gives Anadarko exploration rights to three blocks
covering approximately two million acres on the Black Sea continental shelf and
extending 50 miles offshore. In 2001, the Company completed the processing and
interpretation of about 1,400 miles of seismic data that was acquired in 2000
and conducted additional geological and geophysical analyses. In 2002, the
Company plans to seek a partner to possibly drill wells in the future.
GUATEMALA AND ARGENTINA In 2001, the Company sold its wholly-owned subsidiary,
Basic Resources International (Basic), for $120 million. Basic produces and
refines crude oil in Guatemala. In 2001, the Company also sold its interest in
Argentina for $16 million. The sales were part of the Company's ongoing strategy
to divest low-margin, low-growth projects in its portfolio.
DRILLING PROGRAMS
The Company's 2001 drilling program focused on known oil and gas provinces
in the United States (Lower 48, Gulf of Mexico and Alaska), Canada and Algeria.
Exploration activity consisted of 122 wells, including 58 wells in the Lower 48,
8 wells in Alaska, 8 wells offshore in the Gulf of Mexico, 43 wells in Canada
and 5 wells at other international locations. Development activity consisted of
1,298 wells, which included 797 wells in the Lower 48, 12 wells in Alaska, 11
wells offshore in the Gulf of Mexico, 433 wells in Canada, 19 wells in Algeria
and 26 wells at other international locations.
DRILLING STATISTICS
The following table shows the results of the oil and gas wells drilled and
tested:
<Table>
<Caption>
NET EXPLORATORY NET DEVELOPMENT
------------------------------ ------------------------------
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL TOTAL
---------- --------- ----- ---------- --------- ----- -------
2001
United States 33.6 18.3 51.9 544.0 8.4 552.4 604.3
Canada 28.0 6.0 34.0 381.1 18.0 399.1 433.1
Algeria -- -- -- 3.5 0.2 3.7 3.7
Other International -- 2.7 2.7 11.4 -- 11.4 14.1
----- ----- ----- ----- ----- ----- -------
Total 61.6 27.0 88.6 940.0 26.6 966.6 1,055.2
----- ----- ----- ----- ----- ----- -------
2000
United States 12.9 9.0 21.9 390.8 10.4 401.2 423.1
Canada 8.9 8.0 16.9 98.1 14.4 112.5 129.4
Algeria -- -- -- 1.7 -- 1.7 1.7
Other International -- 0.6 0.6 5.7 -- 5.7 6.3
----- ----- ----- ----- ----- ----- -------
Total 21.8 17.6 39.4 496.3 24.8 521.1 560.5
----- ----- ----- ----- ----- ----- -------
1999
United States 8.4 3.5 11.9 125.6 15.7 141.3 153.2
Algeria -- -- -- 1.9 -- 1.9 1.9
Other International -- 1.4 1.4 -- -- -- 1.4
----- ----- ----- ----- ----- ----- -------
Total 8.4 4.9 13.3 127.5 15.7 143.2 156.5
----- ----- ----- ----- ----- ----- -------
</Table>
21
The following table shows the number of wells in the process of drilling or
in active completion stages and the number of wells suspended or waiting on
completion as of December 31, 2001:
<Table>
<Caption>
WELLS IN THE PROCESS
OF DRILLING OR WELLS SUSPENDED OR
IN ACTIVE COMPLETION WAITING ON COMPLETION
------------------------- -------------------------
EXPLORATION DEVELOPMENT EXPLORATION DEVELOPMENT
----------- ----------- ----------- -----------
UNITED STATES
Gross 19 67 8 39
Net 15.0 52.5 2.9 26.5
CANADA
Gross 12 -- 4 30
Net 12.0 -- 3.0 27.6
ALGERIA
Gross -- 2 -- --
Net -- 0.5 -- --
OTHER INTERNATIONAL
Gross -- 2 -- --
Net -- 1.2 -- --
TOTAL
Gross 31 71 12 69
Net 27.0 54.2 5.9 54.1
</Table>
PRODUCTIVE WELLS
As of December 31, 2001, the Company owned productive wells as follows:
<Table>
<Caption>
OIL WELLS* GAS WELLS*
---------- ----------
UNITED STATES
Gross 6,996 10,716
Net 4,285 6,661
CANADA
Gross 3,497 3,883
Net 1,883 2,832
ALGERIA
Gross 79 --
Net 20 --
OTHER INTERNATIONAL
Gross 303 --
Net 133 --
TOTAL
Gross 10,875 14,599
Net 6,321 9,493
</Table>
- ---------------
* Includes wells containing multiple completions as follows:
<Table>
Gross 617 2,186
Net 488 1,730
</Table>
22
MARKETING AND GATHERING PROPERTIES AND ACTIVITIES
MARKETING The Company, primarily through Anadarko Energy Services (AES),
markets its natural gas, crude oil and NGLs production. In addition, AES seeks
opportunities to capture additional value through downstream trading of
energy-related products and services. In this capacity, AES purchases
third-party production, utilizes transportation, storage and other
energy-related contracts or facilities. Third-party purchases allow the Company
to aggregate larger volumes of gas and attract larger, more creditworthy
customers, which in turn spreads the Company's relatively fixed overhead costs
over more gas and can help to reduce transportation costs. AES does not engage
in market making practices nor does it trade in non-energy-related commodities.
GAS GATHERING Anadarko owns and operates six major gas gathering systems in the
nation's mid-continent area, where the Company has substantial gas production.
The systems are: Antioch Gathering System in the Southwest Antioch field of
Oklahoma; Sneed System in the West Panhandle field of Texas; Hugoton Gathering
System in southwest Kansas; Dew Gathering System in east Texas; Pinnacle
Gathering System in east Texas; and CJV Gathering System in the Carthage field
of east Texas.
The Company's major gathering systems have more than 2,700 miles of
pipeline connecting about 3,100 wells and averaged more than 680 MMcf/d of gas
throughput in 2001. In addition, Anadarko operates numerous other smaller gas
gathering systems.
Anadarko purchased Pinnacle Gas Treating, Inc. for $38 million in January
2001. The purchase gives Anadarko ownership of a natural gas gathering system
that runs through the heart of its Bossier properties. The network, which has a
capacity of 500 MMcf/d of gas, consists of 60 miles of large-diameter pipe, 40
miles of small-diameter laterals and spurs in addition to a 60-mile fuel
redelivery system. The Bethel treating plant acquired in the transaction removes
carbon dioxide and hydrogen sulfide from gas and can handle as much as 500
MMcf/d of gas. In 2001, Anadarko expanded the Bethel plant to accommodate
growing volumes in the area.
MINERALS PROPERTIES AND ACTIVITIES
The Company's minerals operations were acquired in the RME merger
transaction. The minerals operations contribute to the Company's operating
income through non-operated joint venture and royalty arrangements in coal,
trona and industrial mineral mines across the Company's extensive fee mineral
interest in the Land Grant. The Company reinvests the cash flow from its hard
minerals operations primarily into its oil and gas operations.
The Company's low sulfur coal deposits, located primarily in southern
Wyoming, compete with other western coal producers for industrial and utility
boiler markets, which burn the coal to produce steam used to generate
electricity. Most of the Company's coal interests use the surface mining method
of extraction. The Company's coal interests are served by a single rail line and
incur greater transportation costs than some of its competitors in the western
United States. Additionally, competing western coal companies in the Powder
River basin in Wyoming have lower mining costs than the Company's coal
interests. Because of the higher extraction and transportation costs compared to
Powder River basin coal, additional development of the Company's reserves is
dependent on increased coal usage in local markets. In addition to fee mineral
ownership of and royalty interests in coal reserves, the Company owns a 50%
non-operating interest in Black Butte Coal Company. Black Butte Coal Company
produces approximately three million tons of coal per year.
The world's largest deposit of trona, comprising 90% of the world's known
trona resources, is located in the Green River basin in southwestern Wyoming.
Natural soda ash, which is produced by refining trona ore, is used primarily in
the production of glass, in the paper and water treatment industries and in the
manufacturing of certain chemicals and detergents. All of the reserves that can
be mined in the Company's trona deposit lie within the Land Grant and adjoining
lands. The Company owns interests in lands containing approximately 50% of these
reserves and has leased a portion of those lands to companies that mine and
refine trona. Natural soda ash from Wyoming contributes 25% of the world's soda
ash supply with the remainder principally from synthetic processes. In addition
to fee mineral ownership of and royalty interest in trona reserves, the Company
owns a 49% non-operating interest in the OCI Wyoming LP soda ash refining
facility near Green River, Wyoming. Among domestic producers, this facility is
ranked second in soda ash capacity producing over three million tons per year.
23
SEGMENT AND GEOGRAPHIC INFORMATION
Information on operations by segment and geographic location is contained
in Note 11 of the Notes to Consolidated Financial Statements under Item 8 of
this Form 10-K.
EMPLOYEES
As of December 31, 2001, the Company had about 3,500 employees. Relations
between the Company and its employees are considered to be satisfactory and the
Company has had no significant work stoppages or strikes.
REGULATORY MATTERS AND ADDITIONAL FACTORS AFFECTING BUSINESS
See Regulatory Matters and Additional Factors Affecting Business under Item
7 of this Form 10-K.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time properties believed to be suitable for
drilling operations are acquired by the Company. Prior to the commencement of
drilling operations, a thorough title examination of the drill site tract is
conducted and curative work is performed with respect to significant defects, if
any, before proceeding with operations. A thorough title examination has been
performed with respect to substantially all leasehold producing properties owned
by the Company. Anadarko believes the title to its leasehold properties is good
and defensible in accordance with standards generally acceptable in the oil and
gas industry subject to such exceptions which, in the opinion of counsel
employed in the various areas in which the Company has conducted exploration
activities, are not so material as to detract substantially from the use of such
properties. The leasehold properties owned by the Company are subject to
royalty, overriding royalty and other outstanding interests customary in the
industry. The properties may be subject to burdens such as liens incident to
operating agreements and current taxes, development obligations under oil and
gas leases and other encumbrances, easements and restrictions. Anadarko does not
believe any of these burdens will materially interfere with its use of these
properties.
CAPITAL SPENDING
See Capital Resources and Liquidity under Item 7 of this Form 10-K.
RATIOS OF EARNINGS TO FIXED CHARGES AND EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED STOCK DIVIDENDS
As a result of the Company's net loss in 2001, Anadarko's earnings did not
cover fixed charges by $599 million and did not cover combined fixed charges and
preferred stock dividends by $610 million. Anadarko's ratios of earnings to
fixed charges for the years ended December 31, 2000 and 1999 were 7.35 and 1.77,
respectively. The Company's ratios of earnings to combined fixed charges and
preferred stock dividends for the years ended December 31, 2000 and 1999 were
6.80 and 1.53, respectively.
These ratios were computed by dividing earnings by either fixed charges or
combined fixed charges and preferred stock dividends. For this purpose, earnings
include income before income taxes and fixed charges. Fixed charges include
interest and amortization of debt expenses and the estimated interest component
of rentals. Preferred stock dividends are adjusted to reflect the amount of
pretax earnings required for payment.
24
ITEM 2. PROPERTIES
See information appearing under Item 1 of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS
GENERAL The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third-party contractors
alleging exposure to asbestos and benzene while working at a refinery in Corpus
Christi, Texas, which RME sold in segments in 1987 and 1989. While the ultimate
outcome and impact on the Company cannot be predicted with certainty, management
believes that the resolution of these proceedings will not have a material
adverse effect on the consolidated financial position of the Company, although
results of operations and cash flow could be significantly impacted in the
reporting periods in which such matters are resolved. Discussed below are
several specific proceedings.
ROYALTY LITIGATION During September 2000, the Company was named as a defendant
in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et
al. (the "Gas Qui Tam case") filed in the U.S. District Court for the Eastern
District of Texas, Lufkin Division. This lawsuit generally alleges that the
Company and 118 other defendants improperly measured and otherwise undervalued
natural gas in connection with a payment of royalties on production from federal
and Indian lands. The case has been transferred to the U.S. District Court,
Multi-District Litigation Docket pending in Wyoming. Based on the Company's
present understanding of the various governmental and False Claims Act
proceedings described above, the Company believes that it has substantial
defenses to these claims and intends to vigorously assert such defenses.
However, if the Company is found to have violated the False Claims Act, the
Company could be subject to a variety of sanctions, including treble damages and
substantial monetary fines.
A group of royalty owners purporting to represent RME's gas royalty owners
in Texas (Neinast, et al.) was granted class action certification in December
1999, by the 21st Judicial District Court of Washington County, Texas, in
connection with a gas royalty underpayment case against the Company. This
certification did not constitute a review by the Court of the merits of the
claims being asserted. The royalty owners' pleadings did not specify the damages
being claimed, although most recently a demand for damages in the amount of $100
million has been asserted. The Company is of the opinion that the amount of
damages at risk is substantially less than the amount demanded by the class
action counsel and the Company intends to vigorously assert its defenses. The
Company appealed the class certification order. A favorable decision from the
Houston Court of Appeals decertified the class. It is anticipated that the
royalty owners will now appeal this matter to the Texas Supreme Court.
A class action lawsuit entitled Gilbert H. Coulter, et al. v. Anadarko
Petroleum Corporation has been certified in the 26th Judicial District Court,
Stevens County, Kansas. In this action, the royalty owners contend that royalty
was underpaid as a result of the deduction for certain post-production costs in
the calculation of royalty. The Company believes that its method of calculating
royalty was proper and that its gas was marketable in the condition produced,
and thus plaintiffs' claims are without merit. This case was certified as a
class action in August 2000 and was tried in February 2002. A decision from the
trial court is expected by the end of 2002.
WYOMING TAX LITIGATION RME filed tax appeals in March 1999 before the Wyoming
Board of Equalization, alleging that the Wyoming Department of Revenue's
revaluation of RME's crude oil production and natural gas production for the
years 1989 through 1995 was erroneous. RME also filed a lawsuit in September
2000 in the First District Court of Laramie County, Wyoming, alleging that
Wyoming's valuation statute was impermissibly vague. The Department of Revenue
revalued RME's crude oil production based upon prices in Cushing, Oklahoma, as
opposed to the price RME received at the wellhead from its marketing affiliate.
The Department of Revenue also sought to revalue RME's natural gas production
under a new valuation formula that was approved in a decision the Board of
Equalization issued in other litigation while RME's dispute remained pending.
RME argued that the price it received for its crude oil production reflected the
actual market value of the oil at the wellhead, and that it was neither
appropriate nor lawful to value crude oil in Wyoming according to transactions
at Cushing. RME also argued that the formula the Department of
25
Revenue previously had used to value natural gas production for many years was
the proper formula, and that the new formula approved by the Board of
Equalization in the third-party litigation was erroneous. The amount in
controversy was approximately $27 million. The Company settled the dispute for
$10 million, of which RME already had paid $7 million under protest prior to the
merger. As a result of the settlement, the parties have agreed to dismiss the
tax appeals and the lawsuit.
CITGO LITIGATION CITGO Petroleum Corporation's (CITGO) claims arise out of an
Asset Purchase and Contribution Agreement dated March 17, 1987 whereby RME's
predecessor sold a refinery located in Corpus Christi, Texas to CITGO's
predecessor. After the sale of the refinery, numerous individuals living near
the refinery sued CITGO (the Neighborhood Litigation) thereby implicating the
Asset Purchase and Contribution Agreement indemnity provision. CITGO and RME
eventually entered into a settlement agreement to allocate, on an interim basis,
each party's liability for defense and liability cost in that and related
litigation. That agreement provides that once the Neighborhood Litigation and
certain related claims are resolved, then the parties will determine their final
indemnity obligations to each other through binding arbitration. At the present
time, RME and CITGO have agreed to defer arbitrating the allocation of
responsibility for this liability in order to focus their efforts on a global
settlement. Arbitration will resume upon request of either CITGO or RME. In
conjunction with this matter, RME sued Continental Insurance for denial of
coverage for claims related to this dispute. RME and Continental Insurance
settled the insurance coverage litigation which resulted in Continental
Insurance paying RME for the claims. Negotiations and discussions with CITGO
continue.
KANSAS AD VALOREM TAX
General The Natural Gas Policy Act of 1978 allowed a "severance, production or
similar" tax to be included as an add-on, over and above the maximum lawful
price for natural gas. Based on the Federal Energy Regulatory Commission (FERC)
ruling that the Kansas ad valorem tax was such a tax, the Company collected the
Kansas ad valorem tax.
Background of PanEnergy Litigation FERC's ruling regarding the ability of
producers to collect the Kansas ad valorem tax was appealed to the United States
Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The Court
held in June 1988 that FERC failed to provide a reasoned basis for its findings
and remanded the case to FERC.
Ultimately, the D.C. Circuit issued a decision on August 2, 1996 ruling
that producers must refund all Kansas ad valorem taxes collected relating to
production since October 1983. The Company filed a petition for writ of
certiorari with the Supreme Court. That petition was denied on May 12, 1997.
PanEnergy Litigation On May 13, 1997, the Company filed a lawsuit in the
Federal District Court for the Southern District of Texas against PanEnergy
seeking declaration that pursuant to prior agreements Anadarko is not required
to issue refunds to PanEnergy for the principal amount of $14 million (before
taxes) and, if the petition for adjustment is denied in its entirety by FERC
with respect to PanEnergy refunds, interest in an amount of $38 million (before
taxes). The Company also sought from PanEnergy the return of the $1 million
(before taxes) charged against income in 1993 and 1994. In October 2000, the
U.S. Magistrate issued recommendations concerning motions for summary judgment
previously filed by both parties. In essence, the Magistrate's recommendation
finds that the Company should be responsible for refunds attributable to the
time period following August 1, 1985 while Duke Energy (as the successor company
to Anadarko Production Company) should be responsible for refunds attributable
to the time period before August 1, 1985.
The Company has reached a settlement agreement with PanEnergy that requires
the Company to pay $15 million for settlement in full of all matters relating to
the refunds of Kansas ad valorem tax reimbursements collected by the Company as
first seller from August 1, 1985 through 1988. The settlement agreement was
approved by the FERC and paid by Anadarko during 2001. The settlement agreement
does not have any impact on the outstanding dispute between the Company and
PanEnergy in connection with the refunds that relate to the Cimmaron River
System. Anadarko's net income for 2001 included a $15 million charge (before
taxes) related to the settlement agreement. Discussions with the Kansas
Corporation Commission and PanEnergy to reach a settlement of the Cimmaron River
System dispute are ongoing. At this time, it is estimated that a resolution may
be reached in the first half of 2002, that may result in a payment by the
Company of about $7 million. Accordingly, a provision for $7 million was charged
against income in 2001.
26
Other Litigation Anadarko's net income for 1997 included a $2 million charge
(before taxes) related to the Kansas ad valorem tax refunds. This charge
reflects all principal and interest which may be due at the conclusion of all
regulatory proceedings and litigation to parties other than PanEnergy. The
Company is currently unable to predict the final outcome of this matter and no
additional provision for liability has been made in the accompanying financial
statements.
OTHER The Company is subject to other legal proceedings, claims and liabilities
which arise in the ordinary course of its business. In the opinion of the
Company, the liability with respect to these actions will not have a material
effect on the Company.
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 2001.
EXECUTIVE OFFICERS OF THE REGISTRANT
<Table>
<Caption>
AGE AT END
NAME OF 2002 POSITION
---- ---------- --------
Robert J. Allison, Jr. 63 Chairman of the Board
John N. Seitz 51 President and Chief Executive Officer
Charles G. Manley 58 Executive Vice President, Administration
Michael E. Rose 55 Executive Vice President, Finance and Chief
Financial Officer
William D. Sullivan 46 Executive Vice President, Exploration and
Production
Rex Alman III 51 Senior Vice President, Domestic Operations
Michael D. Cochran 60 Senior Vice President, Strategy and Planning
Richard J. Sharples 55 Senior Vice President, Marketing and Minerals
Bruce H. Stover 53 Senior Vice President, Worldwide Business
Development
Robert P. Daniels 43 Vice President, Canada
James J. Emme 46 Vice President, Exploration
Morris L. Helbach 57 Vice President, Information Technology Services and
Chief Information Officer
James R. Larson 52 Vice President and Controller
Richard A. Lewis 58 Vice President, Human Resources
J. Stephen Martin 46 Vice President and General Counsel
J. Anthony Meyer 44 Vice President, Algeria
Mark L. Pease 46 Vice President, International and Alaska Operations
Gregory M. Pensabene 52 Vice President, Government Relations and Public
Affairs
Albert L. Richey 53 Vice President and Treasurer
A. Paul Taylor, Jr. 53 Vice President, Investor Relations
Donald R. Willis 52 Vice President, Corporate Services
</Table>
Mr. Allison relinquished the role of Chief Executive Officer in January
2002 and remains Chairman of the Board. He was named Chairman of the Board and
Chief Executive Officer effective October 1986. He has worked for the Company
since 1973.
Mr. Seitz was named President and Chief Executive Officer in January 2002.
He was named President and Chief Operating Officer in 1999. He was named
Executive Vice President, Exploration and Production and a member of the
Company's Board of Directors during 1997. He has worked for the Company since
1977.
Mr. Manley was named Executive Vice President, Administration in 2000.
Prior to this position, he served as Senior Vice President, Administration. He
has worked for the Company since 1974.
Mr. Rose was named Executive Vice President, Finance and Chief Financial
Officer in 2000. Prior to this position, he served as Senior Vice President,
Finance and Chief Financial Officer. He has worked for the Company since 1978.
27
Mr. Sullivan was named Executive Vice President, Exploration and Production
in 2001. He was named Vice President, Operations -- International, Gulf of
Mexico and Alaska in 2000. Prior to this position, he served as Vice President,
International Operations. He has worked for the Company since 1981.
Mr. Alman was named Senior Vice President, Domestic Operations in 2001.
Prior to this position, he served as Vice President, Domestic Operations. He has
worked for the Company since 1976.
Dr. Cochran was named Senior Vice President, Strategy and Planning in 2001.
Prior to this position he served as Vice President, Exploration. He has been
with the Company since 1987.
Mr. Sharples was named Senior Vice President, Marketing and Minerals in
2001. Prior to this position, he served as Vice President, Marketing. He has
been with the Company since 1993.
Mr. Stover was named Senior Vice President, Worldwide Business Development
in 2001. Prior to this position, he served as Vice President, Worldwide Business
Development since 1998 and Vice President, Acquisitions since 1993. He has
worked for the Company since 1980.
Mr. Daniels was named Vice President, Canada in 2001. Prior to this
position, he was Manager, Onshore Exploration. He has been with the Company
since 1985.
Mr. Emme was named Vice President, Exploration in 2001. He was named Vice
President, Canada in 2000. He has worked for the Company since 1981.
Mr. Helbach joined Anadarko in 2000 as Vice President, Information
Technology Services and Chief Information Officer. Prior to joining Anadarko, he
was General Manager and Chief Information Officer for Information Systems at
Conoco, Inc.
Mr. Larson was named Vice President and Controller in 1995. He had served
as the Company's Controller since 1986. He has worked for the Company since
1983.
Mr. Lewis was named Vice President, Human Resources in 1995. Prior to this
position, he served as Manager of Employee Relations. He has worked for the
Company since 1985.
Mr. Martin was named Vice President and General Counsel in 1995. He has
worked for the Company since 1987.
Mr. Meyer was named Vice President, Algeria in 2001. Prior to this
position, he served as President and General Manager, Anadarko Algeria Company
LLC since 1998. He has worked for the Company since 1981.
Mr. Pease was named Vice President, International and Alaska Operations in
September 2001. Prior to this position, he served as Vice President, Engineering
and Technology since February 2001, Vice President, Algeria since 1998 and as
President and General Manager, Anadarko Algeria Company LLC since 1993. He
joined the Company in 1979.
Mr. Pensabene joined Anadarko in 1997 as Vice President, Government
Relations. In 1999, Public Affairs was added to his responsibilities. Prior to
joining Anadarko, he was a partner in various law firms in Washington, D.C.
Mr. Richey was named Vice President and Treasurer in 1995. He joined the
Company as Treasurer in 1987.
Mr. Taylor was named Vice President, Investor Relations in 1999. Prior to
this position, he served as Vice President, Corporate Communications. He has
worked for the Company since 1986.
Mr. Willis was named Vice President, Corporate Services in 2000. Prior to
this position, he served as Manager, Corporate Administration. He has worked for
the Company since 1979.
All officers of Anadarko are elected in April of each year at an
organizational meeting of the Board of Directors to hold office until their
successors are duly elected and shall have qualified. There are no family
relationships between any directors or executive officers of Anadarko.
28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of Anadarko Petroleum Corporation is traded on the New
York Stock Exchange. Average daily trading volume was 2,726,000 shares in 2001,
1,618,000 shares in 2000 and 672,000 shares in 1999. The ticker symbol for
Anadarko is APC and daily stock reports published in local newspapers carry
trading summaries for the Company under the headings ANADRK or ANADRKPETE. The
following shows information regarding the closing market price of and dividends
paid on the Company's common stock by quarter for 2001 and 2000.
<Table>
<Caption>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
2001
Market Price
High $72.99 $69.00 $59.75 $60.44
Low $54.63 $53.40 $44.05 $47.45
Dividends $ 0.05 $ 0.05 $ 0.05 $0.075
2000
Market Price
High $38.69 $53.25 $68.05 $74.85
Low $28.44 $34.50 $44.44 $58.45
Dividends $ 0.05 $ 0.05 $ 0.05 $ 0.05
</Table>
As of December 31, 2001, there were approximately 26,000 direct holders of
Anadarko common stock. The following table sets forth the amount of dividends
paid on Anadarko common stock during the two years ended December 31, 2001.
<Table>
<Caption>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
millions ------- ------- ------- -------
2001 $12 $13 $12 $20
2000 $ 6 $ 6 $13 $13
</Table>
The amount of future common stock dividends will depend on earnings,
financial condition, capital requirements and other factors, and will be
determined by the Directors on a quarterly basis.
For additional information, see Dividends under Item 7 and Note 8 -- Common
Stock and Stock Options of the Notes to Consolidated Financial Statements under
Item 8 of this Form 10-K.
29
ITEM 6. SELECTED FINANCIAL DATA
<Table>
<Caption>
SUMMARY FINANCIAL INFORMATION*
---------------------------------------------------------
- -------------------------------------------------------------------
% change
MILLIONS, EXCEPT PER SHARE AMOUNTS 2001 2001-2000 2000 1999 1998 1997
---------------------------------- ------- --------- ------- ------ ------- ------
Revenues $ 8,369 52 $ 5,500 $1,706 $ 1,307 $1,570
Operating Income (Loss) (318) n/m 1,419 175 (8) 203
Net Income (Loss) Available to Common
Stockholders before Change in Accounting
Principle (183) n/m 813 32 (49) 107
Net Income (Loss) (188) n/m 796 32 (49) 107
Net Cash Provided by Operating Activities $ 3,321 116 $ 1,536 $ 318 $ 240 $ 362
Per Common Share:
Net Income (Loss) -- Basic $ (0.75) n/m $ 4.32 $ 0.25 $ (0.41) $ 0.90
Net Income (Loss) -- Diluted $ (0.75) n/m $ 4.16 $ 0.25 $ (0.41) $ 0.89
Dividends $ 0.225 13 $ 0.20 $ 0.20 $0.1875 $ 0.15
Average Shares Outstanding -- Basic 250 36 184 125 120 119
Average Shares Outstanding -- Diluted** 250 30 193 126 120 120
Capital Expenditures $ 3,316 94 $ 1,708 $ 680 $ 917 $ 686
------- --- ------- ------ ------- ------
Long-term Debt $ 4,638 16 $ 3,984 $1,443 $ 1,425 $ 956
Stockholders' Equity 6,365 (6) 6,786 1,535 1,259 1,117
Total Assets $16,771 1 $16,590 $4,098 $ 3,633 $2,992
- ---------------------------------------------------------------------------------------------------------
Annual Sales Volumes:
Gas (Bcf) 695 81 385 170 177 179
Oil and Condensate (MMBbls) 68 89 36 15 11 9
NGLs (MMBbls) 15 25 12 7 7 5
Total Barrels of Oil Equivalent (MMBOE) 199 78 112 50 47 44
------- --- ------- ------ ------- ------
Average Daily Sales Volumes:
Gas (MMcf/d) 1,904 81 1,052 465 484 490
Oil and Condensate (MBbls/d) 186 90 98 40 30 25
NGLs (MBbls/d) 42 27 33 18 18 15
Total Barrels of Oil Equivalent (MBOE/d) 546 78 306 135 129 121
------- --- ------- ------ ------- ------
Oil Reserves (MMBbls) 1,132 8 1,046 573 494 420
Gas Reserves (Tcf) 7.0 15 6.1 2.5 2.6 1.7
Total Reserves (MMBOE) 2,305 12 2,061 991 935 708
------- --- ------- ------ ------- ------
Worldwide Finding Cost ($/BOE)*** $ 8.53 19 $ 7.19 $ 4.87 $ 3.13 $ 4.28
Worldwide Reserve Replacement (% of
Production) 221% (79) 1,059% 213% 581% 341%
------- --- ------- ------ ------- ------
Number of Employees 3,500 -- 3,500 1,400 1,500 1,400
- ---------------------------------------------------------------------------------------------------------
</Table>
Bcf -- billion cubic feet
BOE -- barrels of oil equivalent
MBbls/d -- thousand barrels of oil per day
MBOE/d -- thousand barrels of oil equivalent per day
MMBbls -- million barrels
MMBOE -- million barrels of oil equivalent
MMcf/d -- million cubic feet per day
n/m -- not meaningful
Tcf -- trillion cubic feet
- --------------------------------------------------------------------------------
* Consolidated for Anadarko Petroleum Corporation and its principal
subsidiaries, including RME Petroleum Company, RME Holding Company,
Anadarko Canada Energy Ltd., Anadarko Canada Corporation, RME Land Corp.
and Anadarko Algeria Company, LLC. Certain amounts for prior years have
been reclassified to conform to the current presentation. See Management's
Discussion and Analysis of Financial Condition and Results of Operations
under Item 7 and Consolidated Financial Statements and Notes under Item 8
of this Form 10-K.
** For the years 2001 and 1998, 16 million and 1 million, respectively,
potential common shares were not included in the computation of diluted
shares since they had an anti-dilutive effect.
*** Worldwide finding costs are calculated by dividing worldwide costs incurred
by the worldwide reserve additions, excluding sales in place.
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL RESULTS
SELECTED FINANCIAL DATA
<Table>
<Caption>
2001 2000 1999
millions except per share amounts ------ ------ ------
Revenues $8,369 $5,500 $1,706
Costs and expenses 8,687 4,081 1,531
Merger expenses 45 67 --
Interest expense 92 93 74
Other (income) expense (65) (167) (4)
Net income (loss) available to common stockholders before
cumulative effect of change in accounting principle $ (183) $ 813 $ 32
Net income (loss) available to common stockholders $ (188) $ 796 $ 32
Earnings (loss) per share -- before cumulative effect of
change in accounting principle -- basic $(0.73) $ 4.42 $ 0.25
Earnings (loss) per share -- before cumulative effect of
change in accounting principle -- diluted $(0.73) $ 4.25 $ 0.25
Earnings (loss) per share -- basic $(0.75) $ 4.32 $ 0.25
Earnings (loss) per share -- diluted $(0.75) $ 4.16 $ 0.25
</Table>
NET INCOME Anadarko's net loss available to common stockholders for 2001
totaled $188 million, or $0.75 per share (diluted), compared to net income
available to common stockholders for 2000 of $796 million, or $4.16 per share
(diluted). Net income for 2001 includes non-cash charges of $2.55 billion ($1.58
billion after taxes) for impairments of the carrying value of oil and gas
properties primarily in the United States, Canada and Argentina as a result of
low natural gas and oil prices at the end of the third quarter of 2001 as well
as impairments related to exploration efforts in various international locations
during 2001. See Critical Accounting Policies. Excluding the impairments,
Anadarko had net income available to common stockholders of $1.39 billion, or
$5.25 per share (diluted) for 2001. Net income for 2000 includes non-cash
charges of $50 million ($32 million after taxes) for impairments related to
exploration efforts in various international locations. Excluding the
impairments, Anadarko had net income available to common stockholders in 2000 of
$828 million or $4.32 per share (diluted). Anadarko's 1999 net income included a
non-cash charge of $24 million ($15 million after taxes) related to impairments
for exploration efforts in various international locations. Excluding the
impairments, Anadarko had net income in 1999 of $47 million, or $0.37 per share
(diluted). Anadarko's results include the effect of the merger with Union
Pacific Resources Group Inc., subsequently renamed RME Holding Company (RME),
which closed in July 2000, and the acquisition of Berkley Petroleum Corp.
(Berkley), which closed in March 2001.
31
REVENUES
<Table>
<Caption>
2001 2000 1999
millions ------ ------ ------
Gas sales $2,893 $1,591 $ 353
Oil and condensate sales 1,380 948 247
Natural gas liquids sales 255 264 88
Marketing sales 3,776 2,637 1,016
Minerals and other 65 60 2
------ ------ ------
Total $8,369 $5,500 $1,706
------ ------ ------
</Table>
Total revenues for 2001 increased $2.87 billion or 52% compared to 2000.
Natural gas, crude oil and condensate and natural gas liquids (NGLs) revenues
for 2001 increased $1.73 billion or 62% to $4.53 billion compared to $2.80
billion for 2000, due primarily to a significant increase in sales volumes,
partially offset by a decrease in crude oil, condensate and NGLs prices.
Marketing sales for 2001 increased $1.14 billion or 43% compared to 2000. The
increase in marketing sales was due primarily to an increase in marketing sales
volumes, which was partly offset by an increase in marketing purchases of $1.07
billion resulting primarily from higher oil and gas volumes purchased from third
parties.
Anadarko's total revenues for 2000 were up $3.79 billion or 222% compared
to total revenues in 1999. Natural gas, crude oil and condensate and NGLs
revenues for 2000 increased $2.11 billion or 307% to $2.80 billion compared to
$0.69 billion for 1999, due primarily to a significant increase in sales volumes
and commodity prices. Marketing sales for 2000 increased $1.62 billion or 160%
compared to 1999. The increase in marketing sales was due primarily to an
increase in commodity prices, which was offset by an increase in marketing
purchases of $1.67 billion resulting primarily from increased commodity prices
for gas and oil volumes purchased from third parties.
ANALYSIS OF OIL AND GAS SALES VOLUMES
<Table>
<Caption>
2001 2000 1999
---- ---- ----
BARRELS OF OIL EQUIVALENT (MMBOE)
United States 144 83 44
Canada 34 12 --
Algeria 8 10 6
Other International 13 7 --
--- --- --
Total 199 112 50
--- --- --
</Table>
- ---------------
MMBOE -- million barrels of oil equivalent
During 2001, Anadarko sold 199 MMBOE, an increase of 87 MMBOE or 78%
compared to sales of 112 MMBOE in 2000. Approximately 70% of the increase in
volumes during 2001 was due to a full year of operations in 2001 from properties
acquired with the RME merger in July 2000, compared to 5 1/2 months of
operations in 2000. The remainder of the increase in volumes during 2001 was due
primarily to increases of approximately 13 MMBOE from operations in the Gulf of
Mexico, 7 MMBOE related to the acquisition of Berkley in March 2001, 6 MMBOE
from operations in the Bossier play in Texas and Louisiana and 5 MMBOE from
operations in Alaska. The Company's sales volumes were up 62 MMBOE or 124% in
2000 compared to 50 MMBOE in 1999. About 85% of the increase in volumes in 2000
was due to the merger with RME in mid-2000. The remainder of the increase in
volumes during 2000 was due primarily to increases of 4 MMBOE from the Company's
operations in Algeria. Sales volumes represent actual production volumes
adjusted for changes in commodity inventories. Anadarko employs marketing
strategies to help manage production and sales volumes and mitigate the effect
of price volatility, which is likely to continue in the future. See Derivative
Financial Instruments under Item 7a of this Form 10-K.
32
NATURAL GAS SALES VOLUMES AND AVERAGE PRICES
<Table>
<Caption>
2001 2000 1999
------ ------ -----
UNITED STATES (BCF) 573 338 170
MMcf/d 1,569 922 465
Price per Mcf before hedge $ 4.03 $ 4.09 $2.08
Effect of hedge per Mcf 0.12 0.02 --
------ ------ -----
Price per Mcf $ 4.15 $ 4.11 $2.08
------ ------ -----
CANADA (BCF) 121 46 --
MMcf/d 331 127 --
Price per Mcf before hedge $ 4.24 $ 4.42 --
Effect of hedge per Mcf 0.03 (0.04) --
------ ------ -----
Price per Mcf $ 4.27 $ 4.38 --
------ ------ -----
OTHER INTERNATIONAL (BCF) 1 1 --
MMcf/d 4 3 --
Price per Mcf $ 1.22 $ 1.08 --
------ ------ -----
TOTAL (BCF) 695 385 170
MMcf/d 1,904 1,052 465
Price per Mcf before hedge $ 4.06 $ 4.12 $2.08
Effect of hedge per Mcf 0.10 0.01 --
------ ------ -----
Price per Mcf $ 4.16 $ 4.13 $2.08
------ ------ -----
</Table>
- ---------------
Bcf -- billion cubic feet
MMcf/d -- million cubic feet per day
The Company's natural gas sales volumes for 2001 were up 310 Bcf or 81%
compared to 2000. Approximately 70% of the increase in natural gas volumes
during 2001 was due to a full year of production in 2001 from properties
acquired with the RME merger compared to 5 1/2 months of production in 2000. The
remainder of the increase in volumes during 2001 was due primarily to increases
of approximately 44 Bcf from operations in the Gulf of Mexico, 34 Bcf from the
Bossier play in Texas and Louisiana and 29 Bcf related to the acquisition of
Berkley in March 2001. Anadarko's natural gas sales volumes in 2000 were up 215
Bcf or 126% compared to 1999. About 85% of the increase in natural gas volumes
in 2000 was due to the merger with RME in July 2000. The remainder of the
increase in volumes during 2000 was primarily due to increased production in the
Bossier play in east Texas and Louisiana. Production of natural gas is generally
not directly affected by seasonal swings in demand. However, the Company may
decide during periods of low commodity prices to decrease development activity,
which can result in decreased production volumes.
The Company's average wellhead gas price in 2001 was essentially flat
compared to 2000. The higher natural gas prices realized in the first half of
2001 were offset by a decrease in natural gas prices in the second half of 2001.
The decrease in prices during 2001 were attributed to a severe decline in
natural gas demand as a result of high prices in early 2001, a national economic
downturn and mild summer weather. The Company had less than 5% of its forecasted
2002 natural gas wellhead sales volumes hedged as of December 31, 2001. As a
result, future natural gas revenues are subject to continued volatility based on
fluctuations in market prices. Anadarko's average wellhead gas price in 2000
increased 99% from 1999. Natural gas markets improved significantly in 2000,
with the Company's average realized price increasing from $2.08 per Mcf in 1999
to $4.13 per Mcf in 2000. The stronger prices were the result of lower
nationwide production volumes and higher gas demand, particularly from electric
power generation facilities.
33
QUARTERLY NATURAL GAS SALES VOLUMES AND AVERAGE PRICES
<Table>
<Caption>
2001 2000 1999
------ ------ -----
FIRST QUARTER
Bcf 164 44 44
MMcf/d 1,822 486 489
Price per Mcf $ 6.79 $ 2.46 $1.59
SECOND QUARTER
Bcf 184 49 42
MMcf/d 2,018 536 461
Price per Mcf $ 4.49 $ 3.20 $1.95
THIRD QUARTER
Bcf 176 138 42
MMcf/d 1,913 1,498 456
Price per Mcf $ 2.89 $ 3.83 $2.40
FOURTH QUARTER
Bcf 171 154 42
MMcf/d 1,863 1,676 456
Price per Mcf $ 2.59 $ 5.18 $2.40
</Table>
CRUDE OIL AND CONDENSATE SALES VOLUMES AND AVERAGE PRICES
<Table>
<Caption>
2001 2000 1999
------ ------ ------
UNITED STATES (MMBBLS) 34 15 9
MBbls/d 93 40 23
Price per barrel before hedge $22.70 $29.09 $15.87
Effect of hedge per barrel 0.22 (0.37) (0.08)
------ ------ ------
Price per barrel $22.92 $28.72 $15.79
------ ------ ------
CANADA (MMBBLS) 13 4 --
MBbls/d 35 12 --
Price per barrel before hedge $16.90 $27.07 --
Effect of hedge per barrel 0.43 0.31 --
------ ------ ------
Price per barrel $17.33 $27.38 --
------ ------ ------
ALGERIA (MMBBLS) 8 10 6
MBbls/d 22 26 17
Price per barrel $23.97 $28.76 $18.23
------ ------ ------
OTHER INTERNATIONAL (MMBBLS) 13 7 --
MBbls/d 36 20 --
Price per barrel before hedge $14.35 $18.46 --
Effect of hedge per barrel -- (0.11) --
------ ------ ------
Price per barrel $14.35 $18.35 --
------ ------ ------
TOTAL (MMBBLS) 68 36 15
MBbls/d 186 98 40
Price per barrel before hedge $20.14 $26.62 $16.87
Effect of hedge per barrel 0.18 (0.13) (0.04)
------ ------ ------
Price per barrel $20.32 $26.49 $16.83
------ ------ ------
</Table>
- ---------------
MMBbls -- million barrels
MBbls/d -- thousand barrels per day
34
Anadarko's crude oil and condensate sales volumes in 2001 increased 32
MMBbls or 89% compared to 2000. Approximately 65% of the increase in sales
volumes during 2001 was due to a full year of operations in 2001 from properties
acquired with the RME merger compared to 5 1/2 months of operations in 2000. The
remainder of the increase in crude oil and condensate sales volumes during 2001
was due primarily to increases of approximately 6 MMBbls from operations in the
Gulf of Mexico, 5 MMBbls in Alaska and 2 MMBbls related to the acquisition of
Berkley in March 2001. The 2000 oil and condensate volumes increased 21 MMBbls
or 140% compared to 1999. About 85% of the increase in sales volumes in 2000 was
due to the merger with RME in July 2000. The remainder of the increase in
volumes during 2000 was due primarily to increases of 4 MMBbls from the
Company's operations in Algeria. Production of oil usually is not affected by
seasonal swings in demand or in market prices.
Anadarko's average realized crude oil prices for 2001 decreased 23%
compared to 2000. The decrease in crude oil prices during 2001 is attributed
primarily to a modest increase in supply and very slow growth in demand due to a
worldwide economic downturn and a sharp decline in jet fuel consumption. The
Company had less than 8% of its forecasted 2002 crude oil wellhead sales volumes
hedged as of December 31, 2001. As a result, future oil and condensate revenues
are subject to continued volatility based on fluctuations in market prices.
Crude oil prices in 2000 were up 57% compared to 1999. The improvement in crude
oil prices for 2000 was due in large part to a decrease in the production quotas
among the Organization of Petroleum Exporting Countries (OPEC).
QUARTERLY CRUDE OIL AND CONDENSATE SALES VOLUMES AND AVERAGE PRICES
<Table>
<Caption>
2001 2000 1999
------ ------ ------
FIRST QUARTER
MMBbls 17 4 4
MBbls/d 186 49 44
Price per barrel $21.59 $26.28 $10.60
SECOND QUARTER
MMBbls 18 3 4
MBbls/d 192 38 42
Price per barrel $21.38 $26.71 $14.97
THIRD QUARTER
MMBbls 18 13 3
MBbls/d 192 141 30
Price per barrel $21.66 $27.68 $19.32
FOURTH QUARTER
MMBbls 16 15 4
MBbls/d 175 161 44
Price per barrel $16.39 $25.45 $23.02
</Table>
NATURAL GAS LIQUIDS SALES VOLUMES AND AVERAGE PRICES
<Table>
<Caption>
2001 2000 1999
------ ------ ------
TOTAL (MMBBLS) 15 12 7
MBbls/d 42 33 18
Price per barrel $16.51 $21.70 $13.40
</Table>
The Company's NGLs sales volumes in 2001 increased 25% compared to 2000.
NGLs sales volumes in 2000 increased 71% compared to 1999. The 2001 average NGLs
prices decreased 24% compared to 2000. By comparison, 2000 NGLs prices were 62%
above 1999. NGLs production is dependent on natural gas prices and the economics
of processing the natural gas volumes to extract NGLs.
35
COSTS AND EXPENSES
<Table>
<Caption>
2001 2000 1999
millions ------ ------ ------
Marketing purchases $3,704 $2,638 $ 972
Operating expenses 716 438 179
Administrative and general 247 180 102
Depreciation, depletion and amortization 1,154 593 218
Other taxes 247 128 36
Provisions for doubtful accounts -- 23 --
Impairments related to oil and gas properties 2,546 50 24
Amortization of goodwill 73 31 --
------ ------ ------
Total $8,687 $4,081 $1,531
------ ------ ------
</Table>
During 2001, Anadarko's costs and expenses increased $4.61 billion or 113%
compared to 2000 due to the following factors:
-- Marketing purchases increased $1.07 billion (40%) due primarily to an
increase in oil and gas volumes purchased from third parties.
-- Operating expenses increased $278 million (63%) primarily due to a
significant increase in the number of producing wells as a result of the
RME merger in mid-2000, the Berkley acquisition in early 2001 and
significant development activity in the Gulf of Mexico, Alaska and the
Bossier play in east Texas and Louisiana. Operating expenses were also
impacted by an increase in oil field service costs.
-- Administrative and general expenses increased $67 million (37%)
primarily due to the Company's expanded workforce resulting from the RME
merger in mid-2000 and higher costs associated with the Company's
growing workforce.
-- Depreciation, depletion and amortization (DD&A) expense increased $561
million (95%). About 80% of the increase was due to the increase in
volumes as a result of the RME merger, the Berkley acquisition and
significant development activity. The remaining increase is due to
increases in the DD&A rate, which is also due to the RME merger and
Berkley acquisition. As a result of the ceiling test impairments related
to low oil and gas prices at the end of the third quarter of 2001, DD&A
expense will be reduced in the future.
-- Other taxes increased $119 million (93%). Approximately 50% of the
increase was due to an increase in ad valorem taxes as a result of the
significant increase in properties as a result of the merger and
acquisitions. The remainder of the increase is primarily due to an
increase in production taxes as a result of the increase in volumes.
-- Impairments in 2001 were due to low oil and gas prices at the end of the
third quarter of 2001, which resulted in ceiling test impairments for
the United States ($1.70 billion), Canada ($808 million), Argentina ($15
million) and Brazil ($4 million), as well as unsuccessful exploration
activities in the United Kingdom ($11 million) and Ghana ($7 million).
-- Amortization of goodwill increased $42 million due to the RME merger in
mid-2000 ($32 million) and the Berkley acquisition in 2001 ($10
million).
During 2000, Anadarko's costs and expenses increased $2.55 billion or 167%
compared to 1999 due to the following factors:
-- Marketing purchases increased $1.67 billion (171%) due primarily to an
increase in commodity prices for gas and oil volumes purchased from
third parties.
-- Operating expenses increased $259 million (145%) due primarily to the
significant increase in number of producing wells as a result of the RME
merger and higher downstream expenses associated with an increase in
NGLs production.
-- Administrative and general expenses were up $78 million (76%) due
primarily to an increase in costs associated with the Company's growing
workforce as a result of the RME merger in mid-2000.
-- DD&A expense increased $375 million (172%). About 76% of the increase
was due to a 124% increase in volumes as a result of the RME merger and
higher volumes in Algeria and the Bossier
36
play in east Texas and Louisiana. The remaining increase is due
primarily to an increase in the DD&A rate as a result of the RME merger.
-- Other taxes increased $92 million (256%). Approximately 75% of the
increase was due to an increase in production taxes as a result of
higher volumes associated with the RME merger and an increase in
commodity prices in 2000. The remainder of the increase was due to
higher ad valorem taxes as a result of the significant increase in
properties and higher payroll taxes as a result of the increase in
employees as a result of the RME merger.
-- Provisions for doubtful accounts increased $23 million due to default by
one creditor.
-- Impairments in 2000 related to unsuccessful exploration activities in
the United Kingdom ($17 million), Tunisia ($13 million), Ireland ($10
million) and other international locations ($10 million).
-- Amortization of goodwill was $31 million due to the RME merger in
mid-2000.
MERGER EXPENSES
During 2001 and 2000, merger costs of $41 million and $67 million,
respectively, were expensed related to the RME merger. These costs relate
primarily to the issuance of stock for retention of employees, deferred
compensation, transition, integration, hiring and relocation costs, vesting of
restricted stock and stock options and retention bonuses. For 2001, merger costs
of $4 million were expensed related to the Berkley and Gulfstream Resources
Canada Limited (Gulfstream) acquisitions. There were no merger related expenses
in 1999. Any additional expenses related to the RME, Berkley or Gulfstream
acquisitions are expected to be minimal and will be included in administrative
and general expenses in the future.
INTEREST EXPENSE
<Table>
<Caption>
2001 2000 1999
millions ----- ----- ----
Gross interest expense $ 301 $ 193 $ 96
Capitalized interest (209) (100) (22)
----- ----- ----
Net interest expense $ 92 $ 93 $ 74
----- ----- ----
</Table>
Anadarko's gross interest expense has increased over the past three years
due primarily to the RME merger in mid-2000 and the Berkley acquisition in 2001
as well as higher levels of borrowings for capital expenditures, including
producing property acquisitions. Gross interest expense in 2001 increased 56%
compared to 2000 primarily due to the RME merger in mid-2000 and the Berkley
acquisition in 2001 which resulted in higher average borrowings during 2001.
Gross interest expense in 2000 was up 101% compared to 1999 primarily due to the
RME merger and higher average borrowings in 2000. See Capital Resources and
Liquidity and Outlook on Liquidity.
In 2001, capitalized interest increased by 109% compared to 2000 primarily
due to an increase in costs excluded from the DD&A pools related to the RME
merger in mid-2000 and the Berkley acquisition in 2001. In 2000, capitalized
interest increased by 355% compared to 1999 primarily due to an increase in
costs excluded related to the RME merger. For additional information about the
Company's policies regarding costs excluded and capitalized interest see
Critical Accounting Policies -- Costs Excluded and Capitalized Interest.
OTHER (INCOME) EXPENSE
<Table>
<Caption>
2001 2000 1999
millions ---- ----- ----
Firm transportation keep-whole contract valuation $(91) $(175) $--
Foreign currency exchange 29 7 --
Change in time value options (18) -- --
Other 15 1 (4)
---- ----- ---
Total $(65) $(167) $(4)
---- ----- ---
</Table>
Other income in 2001 decreased $102 million or 61% compared to the same
period of 2000 due primarily to an $84 million decrease related to the effect of
significantly lower market value for firm transportation
37
subject to a keep-whole agreement and a $22 million increase in foreign currency
exchange losses primarily due to changes in the Canadian exchange rates. Other
income for 2000 includes $175 million related to the effect of significantly
higher market values for firm transportation subject to a keep-whole agreement.
The keep-whole agreement was acquired with the RME merger in 2000. See
Derivative Financial Instruments and Foreign Currency Risk under Item 7a of this
Form 10-K.
MARKETING STRATEGIES
OVERVIEW The Company's sales of natural gas, crude oil, condensate and NGLs are
generally made at the market prices of those products at the time of sale.
Therefore, even though the Company has several large purchasers, the Company
believes other purchasers would be willing to buy the Company's natural gas,
crude oil, condensate and NGLs at comparable market prices. The Company's
marketing department actively manages sales of its oil and gas through Anadarko
Energy Services Company (AES), Anadarko, Anadarko Canada Corporation and RME.
The Company also conducts trading activities for the purpose of generating
profits on or from exposure to changes in the market prices of gas, crude oil,
condensate and NGLs. However, the Company does not engage in market-making
practices nor does it trade in any non-energy-related commodities. The Company's
trading risk position, most of the time, is a net short position that is offset
by the Company's natural long position as a producer. Essentially all of the
Company's trading transactions have a term of less than one year and most are
less than three months. See Derivative Financial Instruments under Item 7a of
this Form 10-K.
NATURAL GAS The North American natural gas market has grown significantly
throughout the last 10 years and management believes continued growth to be
likely. Natural gas prices have been extremely volatile and are expected to
continue to be so. Management believes the Company's excellent portfolio of
exploration and development prospects should position Anadarko to continue to
participate in this growth. Anadarko's wholly-owned marketing
subsidiary -- AES -- is a full-service marketing company offering supply
assurance, competitive pricing and services tailored to its customers' needs.
Approximately 36% of the Company's gas production was sold through AES in 2001.
AES also purchases and sells third-party produced gas in the Company's market
areas. Third-party purchases allow the Company to aggregate larger volumes of
gas and attract larger, more creditworthy customers, which in turn spreads the
Company's relatively fixed overhead costs over more gas and can help to reduce
transportation costs. AES sells natural gas under a variety of contracts and may
also receive a service fee related to the level of reliability and service
required by the customer. AES has the marketing capability to move large volumes
of gas into and out of the "daily" gas market to take advantage of any price
volatility. Included in this strategy is the use of leased natural gas storage
facilities and various derivative financial instruments. The Company also
conducts trading activities for the purpose of generating profits on or from
exposure to changes in the market price of natural gas.
RME was a party to several long-term firm gas transportation agreements
that supported the gas marketing program within the gathering, processing and
marketing (GPM) business segment, which was sold in 1999 to Duke Energy Field
Services, Inc. (Duke). Most of the GPM's firm long-term transportation contracts
were transferred to Duke in the GPM disposition. One contract was retained, but
is managed and operated by Duke. Anadarko is not responsible for the operations
of the contracts and does not utilize the associated transportation assets to
transport the Company's natural gas. As part of the GPM disposition, RME and
Duke signed a keep-whole agreement, under which RME will pay Duke if the
transportation market values fall below the fixed contract transportation rates,
while Duke will pay RME if the transportation market values exceed the contract
transportation rates (keep-whole agreement). The fair value of the short-term
portion of the firm transportation keep-whole agreement is calculated with
actively quoted natural gas basis prices. Basis is the difference in value
between gas at various delivery points and the NYMEX gas futures contract price.
Management believes that natural gas basis price quotes beyond the next twelve
months are not reliable indicators of fair value due to decreasing liquidity.
Accordingly, the fair value of the long-term portion is estimated based on
historical natural gas basis prices, discounted at a 10% per year. Management
also periodically evaluates the supply and demand factors (such as expected
drilling activity, anticipated pipeline construction projects, expected changes
in demand at pipeline delivery points) that may impact the future market value
of the firm transportation capacity to determine if the estimated fair value
should be adjusted.
38
In 2001 and 2000, approximately 31% and 56%, respectively, of the Company's
gas production was sold under long-term contracts to Duke Energy. These sales
represent 17% and 18%, respectively, of total revenues in 2001 and 2000. Most of
the Company's gas production sold to Duke Energy is under a single agreement
that expires at the end of the first quarter of 2004. Volumes sold to Duke under
this contract may be delivered at a number of locations generally at the
tailgate of processing facilities owned or operated by Duke Energy or its
affiliates and typically in the general vicinity of the fields where produced.
The pricing of gas under this contract is market based and therefore varies
monthly and by region.
CRUDE OIL, CONDENSATE AND NGLS Anadarko's crude oil, condensate and NGLs
revenues are derived from production in the U.S., Canada, Algeria and other
international areas. Most of the Company's U.S. crude oil and NGLs production is
on 30-day "evergreen" contracts with prices based on marketing indices and
adjusted for location, quality and transportation. Most of the Company's
Canadian oil production is sold on a term basis of one year or greater. Oil from
Algeria is sold by tanker as Saharan Blend to customers primarily in the
Mediterranean area. Saharan Blend is a high quality crude that provides refiners
with large quantities of premium products like high quality jet and diesel fuel.
AES purchases and sells third-party crude oil, condensate and NGLs in the
Company's domestic and international market areas. Included in this strategy is
the use of leased crude oil storage facilities and various derivative financial
instruments.
GAS GATHERING SYSTEMS AND PROCESSING Anadarko's investment in gas gathering
operations allows the Company to better manage its gas production, improve
ultimate recovery of reserves, enhance the value of gas production and expand
marketing opportunities. The Company has invested $173 million to build or
acquire gas gathering systems over the last five years. The vast majority of the
gas flowing through these systems is from Anadarko operated wells.
The Company processes gas at various third-party plants under agreements
generally structured to provide for the extraction and sale of NGLs in efficient
plants with flexible commitments. Anadarko also processes gas and has interests
in one operated plant and three non-operated plants. Anadarko's strategy to
aggregate gas through Company-owned and third-party gathering systems allows
Anadarko to secure processing arrangements in each of the regions where the
Company has significant production.
Anadarko purchased Pinnacle Gas Treating, Inc., for $38 million, in January
2001. The purchase gives Anadarko ownership of a natural gas gathering system
that runs through the heart of its Bossier properties. The acquisition provides
the Company greater flexibility in shipping and marketing its gas from the area
as well as improved service to other shippers. The network, which has a capacity
of 500 MMcf/d of gas, consists of 60 miles of large-diameter pipe, 40 miles of
small-diameter laterals and spurs in addition to a 60-mile fuel redelivery
system. In 2001, Anadarko expanded the Bethel plant acquired in the transaction
to accommodate growing volumes in the area. The Bethel treating plant removes
carbon dioxide and hydrogen sulfide from gas and can handle as much as 500
MMcf/d of gas.
MARKETING CONTRACTS The following schedules provide additional information
regarding the Company's marketing and trading portfolio of physical and
derivative contracts and the firm transportation keep-whole agreement as of
December 31, 2001. The Company records income on these activities using the
mark-to-market method. See Critical Accounting Policies for an explanation of
how the fair value for derivatives are calculated. In 2001, the use of
mark-to-market accounting compared to historical cost accounting resulted in
additional non-cash income of $31 million, before taxes, related to the
marketing and trading activities and reduced non-cash income related to the firm
transportation keep-whole agreement by $74 million, before taxes.
<Table>
<Caption>
FIRM
MARKETING TRANSPORTATION
AND TRADING KEEP-WHOLE TOTAL
millions ----------- -------------- -----
Fair value of contracts outstanding at December 31, 2000 $(12) $ 40 $ 28
Contracts realized or otherwise settled during 2001 (22) (213) (235)
Fair value of new contracts when entered into during 2001 10 -- 10
Other changes in fair value 41 91 132
---- ----- -----
Fair value of contracts outstanding at December 31, 2001 $ 17 $ (82) $ (65)
---- ----- -----
</Table>
39
<Table>
<Caption>
FAIR VALUE OF CONTRACTS AT DECEMBER 31, 2001
------------------------------------------------------
MATURITY MATURITY
LESS THAN MATURITY MATURITY IN EXCESS
ASSETS (LIABILITIES) 1 YEAR 1-3 YEARS 4-5 YEARS OF 5 YEARS TOTAL
millions --------- --------- --------- ---------- -----
MARKETING AND TRADING
Prices actively quoted $15 $ 1 $ -- $ -- $ 16
Prices based on models and other
valuation methods 1 -- -- -- 1
FIRM TRANSPORTATION KEEP-WHOLE
Prices actively quoted $(2) $ -- $ -- $ -- $ (2)
Prices based on models and other
valuation methods -- (40) (27) (13) (80)
TOTAL
Prices actively quoted $13 $ 1 $ -- $ -- $ 14
Prices based on models and other
valuation methods 1 (40) (27) (13) (79)
</Table>
OPERATING RESULTS
DRILLING ACTIVITY During 2001, Anadarko participated in a total of 1,420 gross
wells, including 970 gas wells, 375 oil wells and 75 dry holes. This compares to
709 gross wells (385 gas wells, 269 oil wells and 55 dry holes) in 2000 and 200
gross wells (122 gas wells, 52 oil wells and 26 dry holes) in 1999. The increase
in activity during 2001 was a result of the RME merger, the Berkley acquisition
and improved commodity prices at the beginning of the year.
The Company's 2001 exploration and development drilling program is
discussed in Oil and Gas Properties and Activities under Item 1 of this Form
10-K.
DRILLING PROGRAM ACTIVITY
<Table>
<Caption>
GAS OIL DRY TOTAL
----- ----- ---- -----
2001 EXPLORATORY
Gross 47 35 40 122
Net 35.6 26.0 27.0 88.6
2001 DEVELOPMENT
Gross 923 340 35 1,298
Net 677.5 262.5 26.6 966.6
2000 EXPLORATORY
Gross 17 15 24 56
Net 11.7 10.1 17.6 39.4
2000 DEVELOPMENT
Gross 368 254 31 653
Net 300.3 196.0 24.8 521.1
</Table>
- ---------------
Gross: total wells in which there was participation.
Net: working interest ownership.
RESERVE REPLACEMENT Drilling activity is not the best measure of success for an
exploration and production company. Anadarko focuses on growth and
profitability. Reserve replacement is the key to growth and future profitability
depends on the cost of finding oil and gas reserves, among other factors. The
Company believes its performance in both areas is excellent. For the 20th
consecutive year, Anadarko more than replaced annual production volumes with
proved reserves of natural gas, crude oil, condensate and NGLs, stated on a
barrel of oil equivalent (BOE) basis.
40
During 2001, Anadarko's worldwide reserve replacement was 221% of total
production -- which reached a record of 201 MMBOE. The Company's worldwide
reserve replacement in 2000 was 1,059% of total production of 112 MMBOE. The
Company's worldwide reserve replacement in 1999 was 213% of total production of
50 MMBOE. Over the last five years, the Company's annual reserve replacement has
averaged 476% of annual production volumes.
Excluding mergers, acquisitions and divestitures, Anadarko's worldwide
reserve replacement for 2001 was 173% of total production compared to 231% for
2000 and 236% for 1999. Excluding mergers, acquisitions and divestitures, the
Company's annual worldwide reserve replacement over the past five years averaged
243% of annual production volumes.
Anadarko continues to increase its energy reserves in the U.S. In 2001, the
Company replaced 161% of its U.S. production volumes with U.S. reserves. This
compares to a U.S. reserve replacement of 855% in 2000 and 128% in 1999. The
Company's U.S. reserve replacement for the five-year period 1997-2001 was 360%
of production. Excluding mergers, acquisitions and divestitures, Anadarko's U.S.
reserve replacement for 2001, 2000 and 1999 was 160%, 207% and 101%,
respectively, of total production. The Company's U.S. reserve replacement for
the five-year period 1997-2001 was 195% excluding mergers, acquisitions and
divestitures. By comparison, the most recent published U.S. industry average
(1996-2000) was 109%. (Source: U.S. Department of Energy) Anadarko's U.S.
reserve replacement performance for the same period 1996-2000 was 452% of
production or 218% of production, excluding mergers, acquisitions and
divestitures. Industry data for 2001 are not yet available.
COST OF FINDING Cost of finding results in any one year can be misleading due
to the long lead times associated with exploration and development. A better
measure of cost of finding performance is over a five-year period. Anadarko has
historically outperformed the industry in average finding costs. For the period
1997-2001, Anadarko's worldwide finding cost was $6.66 per BOE. The Company's
U.S. finding cost for the same five-year period was $7.58 per BOE. Excluding
mergers and acquisitions, Anadarko's worldwide and U.S. finding costs for the
five-year period 1997-2001 were $5.88 per BOE and $6.78 per BOE, respectively.
Industry data for 2001 are not yet available. For comparison purposes, the most
recently published five-year average (1996-2000) for the industry shows
worldwide finding cost was $4.32 per BOE and U.S. finding cost was $5.63 per
BOE. (Source: Arthur Andersen) For the same five-year period of 1996-2000,
Anadarko's worldwide finding cost was $5.89 per BOE and its U.S. finding cost
was $6.86 per BOE. For the five-year period 1996-2000, the Company's worldwide
and U.S. finding costs excluding mergers and acquisitions were $4.30 per BOE and
$5.15 per BOE, respectively.
For 2001, Anadarko's worldwide finding cost was $8.53 per BOE. This
compares to $7.19 per BOE in 2000 and $4.87 per BOE in 1999. Anadarko's U.S.
finding cost for 2001 was $9.60 per BOE. This compares to $8.49 per BOE in 2000
and $9.06 per BOE in 1999. Excluding mergers and acquisitions, Anadarko's
worldwide finding costs for 2001 was $8.75 per BOE compared to $5.83 per BOE in
2000 and $5.17 per BOE in 1999. The Company's U.S. finding costs excluding
mergers and acquisitions for 2001 was $9.46 per BOE compared to $6.77 per BOE in
2000 and $11.52 per BOE in 1999. Finding costs in 2001 have increased due
primarily to increases in oilfield services costs and increased exploration and
development activity.
PROVED RESERVES At the end of 2001, Anadarko's proved reserves were 2.3 billion
BOE compared to 2.1 billion BOE at year-end 2000 and 991 MMBOE at year-end 1999.
Reserves increased 12% in 2001 compared to 2000 due primarily to exploration and
development drilling in both the U.S. and overseas and the Berkley and
Gulfstream acquisitions. Anadarko's proved reserves have grown 147% over the
past three years, primarily as a result of the RME merger in 2000, the Berkley
and Gulfstream acquisitions in 2001, successful exploration projects in Alaska,
Algeria and the Gulf of Mexico, and successful development drilling programs in
major domestic fields in core areas onshore and offshore.
The Company's proved natural gas reserves at year-end 2001 were 7.04
trillion cubic feet (Tcf) compared to 6.09 Tcf at year-end 2000 and 2.51 Tcf at
year-end 1999. Anadarko's proved gas reserves have increased 166% since year-end
1998, reflecting the RME merger in 2000 and the Berkley and Gulfstream
acquisitions in 2001, continued development activity onshore in the U.S. and
other producing property acquisitions. Anadarko's crude oil, condensate and NGLs
reserves at year-end 2001 increased 8% to 1.13 billion barrels compared to 1.05
billion barrels at year-end 2000 and 573 MMBbls at year-end 1999. Crude oil
reserves have risen by 129% over the last three years primarily due to the RME
merger in 2000, the Berkley and Gulfstream
41
acquisitions in 2001 and large discoveries in Alaska, Algeria and the Gulf of
Mexico. Crude oil, condensate and NGLs reserves comprise 49% of the Company's
proved reserves at year-end 2001 compared to 51% at year-end 2000 and 58% at
year-end 1999.
At December 31, 2001, the present value (discounted at 10%) of future net
revenues from Anadarko's proved reserves was $11.5 billion, before income taxes,
and was $8.0 billion, after income taxes, (stated in accordance with the
regulations of the Securities and Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB)). This present value was calculated based on
prices at year-end held flat for the life of the reserves, adjusted for any
contractual provisions. The after income taxes decrease of $13.4 billion or 62%
in 2001 compared to 2000 is primarily due to significantly lower natural gas and
crude oil prices at year-end 2001, partially offset by additions of proved
reserves related to successful drilling worldwide and the Berkley and Gulfstream
acquisitions. See Critical Accounting Policies under Item 7 and Supplemental
Information on Oil and Gas Exploration and Production Activities -- Unaudited in
the Consolidated Financial Statements under Item 8 of this Form 10-K.
The present value of future net revenues does not purport to be an estimate
of the fair market value of Anadarko's proved reserves. An estimate of fair
value would also take into account, among other things, anticipated changes in
future prices and costs, the expected recovery of reserves in excess of proved
reserves and a discount factor more representative of the time value of money
and the risks inherent in producing oil and gas.
ACQUISITIONS AND DIVESTITURES
The Company's strategy includes an active asset acquisition and divestiture
program. In 2001, the Company acquired approximately 157 MMBOE of proved
reserves, located in: Canada, primarily from the Berkley acquisition (99 MMBOE),
Qatar and Oman with the Gulfstream acquisition (57 MMBOE) and the United States
(1 MMBOE). In 2000, Anadarko acquired with the RME merger approximately 912
MMBOE of proved reserves, located primarily in the United States, Canada and
Latin America. Excluding the RME, Berkley and Gulfstream acquisition
transactions, during 1999-2001, Anadarko acquired through purchases and trades
33 MMBOE of proved reserves for $118 million. During the same time period, the
Company sold properties, either as a strategic exit from a certain area or asset
rationalization in existing core areas, with proceeds totaling $289 million.
Reserves associated with these sales and trades were 90 MMBOE. In 2002, the
Company will continue to consider dispositions of certain producing properties
in non-core areas.
PROPERTIES AND LEASES
PRODUCING PROPERTIES The Company owns 9,493 net producing gas wells and 6,321
net producing oil wells worldwide. The following schedule shows the number of
developed and undeveloped lease acres in which Anadarko held interests at
December 31, 2001.
ACREAGE
<Table>
<Caption>
DEVELOPED UNDEVELOPED TOTAL
--------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
thousands ------ ------ ------ ------ ------ ------
United States
Onshore -- Lower 48 2,714 1,901 2,322 1,583 5,036 3,484
Offshore 483 220 1,251 892 1,734 1,112
Alaska 32 7 1,400 481 1,432 488
------ ------ ------ ------ ------ ------
Total 3,229 2,128 4,973 2,956 8,202 5,084
------ ------ ------ ------ ------ ------
Canada 1,942 1,118 9,102 3,554 11,044 4,672
Algeria* 209 50 3,387 1,176 3,596 1,226
Other International 427 87 29,981 15,314 30,408 15,401
</Table>
- ---------------
* Developed acreage in Algeria relates only to areas with an Exploitation
License. A portion of the undeveloped acreage in Algeria will be relinquished
in the future upon finalization of Exploitation License boundaries.
42
LAND GRANT AND OTHER FEE MINERALS The Company also owns fee mineral interests
on acreage totaling 10,138,000 (gross) or 9,109,000 (net) acres as of December
31, 2001. Of this amount, 7,929,000 (gross) or 7,740,000 (net) acres are within
the Company's Land Grant area in Wyoming, Colorado and Utah, which was granted
by the federal government to a predecessor of RME in the mid-1800s. The Company
holds royalty interests of varying percentages in approximately one million
gross acres of the Land Grant that are subject to exploration and production
agreements with third-parties. The Company's fee mineral acreage is primarily
undeveloped.
CAPITAL RESOURCES AND LIQUIDITY
CAPITAL EXPENDITURES*
<Table>
<Caption>
2001 2000 1999
millions ------ ------ ----
Development $1,641 $ 921 $311
Exploration 1,030 429 189
Acquisitions of producing properties 14 54 50
Gathering and other 244 80 27
Capitalized interest and exploration and development costs 387 224 103
------ ------ ----
Total $3,316 $1,708 $680
------ ------ ----
</Table>
- ---------------
* Excludes corporate acquisitions
The Company's primary focus for 2001 was to develop existing fields and
find additional reserves in the Lower 48 states, the Gulf of Mexico and in
Canada. Anadarko's total capital spending in 2001 was $3.3 billion, a 94%
increase compared to 2000. The increase from 2000 represents a $720 million
increase in development spending, a $601 million increase in exploration
spending and a $287 million increase in spending primarily for general
properties and capitalized interest. The development spending increase was
primarily in the Lower 48 states, while the exploration spending increase was
primarily in the Gulf of Mexico and the Lower 48 states.
Anadarko's total capital spending for 2000 was $1.7 billion, a 151%
increase compared to 1999. The increase from 1999 represents a $610 million
increase in development spending, a $240 million increase in exploration
spending and a $178 million increase in spending for capitalized interest and
other costs. The increase in development spending was primarily related to the
United States and Canada as a result of the RME merger, as well as an increase
in Algeria's construction development spending.
The Company funded its capital investment programs in 2001, 2000 and 1999
primarily through cash flow, plus increases in long-term debt, issuances of
common stock and proceeds from property sales.
Capital spending for 2002 has been initially set at $2.0 billion, which is
a 40% decrease compared to 2001. The primary focus of the 2002 budget is to find
additional oil and gas reserves and maintain Company-wide production at current
levels. Anadarko has allocated nearly $1.0 billion to worldwide development
projects, primarily for fields in the Gulf of Mexico, western Canada, east and
central Texas, north Louisiana, the western states and Algeria. Approximately
$500 million is budgeted for exploration programs, mainly in the Gulf of Mexico,
east Texas, north Louisiana, Alaska, western Canada, Congo and Australia. About
70% of the exploration budget will be for drilling. The remainder of the
exploration budget will be used for seismic and lease acquisitions. See Outlook
on Liquidity for a discussion of the sources of funds for capital spending.
DEBT At year-end 2001, Anadarko's total debt was $5.1 billion. This compares to
total debt of $4.0 billion at year-end 2000 and $1.4 billion at year-end 1999.
As a result of the RME merger, the liabilities of RME became liabilities of the
Company. The increases in debt are related primarily to the RME merger in 2000
and the Berkley and Gulfstream acquisitions in 2001.
In March 2001, Anadarko issued $650 million of Zero Yield Puttable
Contingent Debt Securities (ZYP-CODES) due 2021 to qualified institutional
buyers under Rule 144A and non-U.S. persons under Regulation S. The debt
securities were priced with a zero coupon, zero yield to maturity and a
conversion premium of 38%. The proceeds from the debt securities were used
initially to finance costs associated with the
43
acquisition of Berkley. Holders of the ZYP-CODES have the right to require
Anadarko to purchase all or a portion of their ZYP-CODES in March 2002, 2004,
2006, 2011 or 2016, at $1,000 per ZYP-CODES. In March 2002, ZYP-CODES in the
amount of $620 million were put to the Company for repayment and were paid in
cash.
In April 2001, Anadarko Finance Company, a wholly-owned finance subsidiary
of Anadarko, issued $1.3 billion in notes as part of the Company's financial
restructuring plan. This issuance was made up of $400 million of 6 3/4% Notes
due 2011 and $900 million of 7 1/2% Notes due 2031. In May 2001, Anadarko
Finance Company issued an additional $550 million of 6 3/4% Notes due 2011,
bringing the 6 3/4% Notes to an aggregate total of $950 million. The notes are
fully and unconditionally guaranteed by Anadarko. The notes were issued as part
of an exchange of securities for other Anadarko debt.
In October 2001, the Company entered into a Revolving Credit Agreement and
a 364-Day Revolving Credit Agreement. Each agreement provides for a $225 million
principal amount and expires in 2004 and 2002, respectively. In October 2001,
Anadarko Canada Corporation, a wholly-owned subsidiary of Anadarko, entered into
a 364-Day Canadian Credit Agreement. The agreement provides for a US$300 million
principal amount and expires in 2002. The agreement is fully and unconditionally
guaranteed by Anadarko. As of December 31, 2001, the Company had $69 million
outstanding under the Canadian Credit Agreement.
In February 2002, the Company issued $650 million principal amount of
5 3/8% Notes due March 2007. In March 2002, the Company issued $400 million
principal amount of 6 1/8% Notes due March 2012. The net proceeds from these
issuances were used to reduce floating-rate debt and to fund a portion of the
ZYP-CODES put to the Company for repayment in March 2002.
PREFERRED STOCK During 2001, Anadarko repurchased $97 million of preferred
stock. The resulting gain of $13 million was recorded to paid-in capital.
COMMON STOCK PURCHASE PROGRAM In July 2001, the Board of Directors authorized
the Company to purchase up to $1 billion in shares of Anadarko common stock. The
share purchases may be made from time to time, depending on market conditions.
Shares may be purchased either in the open market or through privately
negotiated transactions. The repurchase program does not obligate Anadarko to
acquire any specific number of shares and may be discontinued at any time.
To enhance the share repurchase program, Anadarko has sold put options to
independent third parties. These put options entitle the holder to sell shares
of Anadarko common stock to the Company on certain dates at specified prices.
During 2001, Anadarko sold put options for the purchase of a total of 5 million
shares of Anadarko common stock with a notional amount of $240 million. Put
options for 1 million shares were exercised and put options for 2 million shares
expired unexercised in 2001. During 2001, premiums of $15 million were received
related to these put options and recorded as an increase to paid-in capital. In
January 2002, the Company entered into additional put options for 1 million
shares of Anadarko common stock with a notional amount of $46 million and
received a $3 million premium. Put options for an additional 1 million shares
expired unexercised in 2002. The remaining put options for 2 million shares will
expire in March and July 2002, if not exercised. The put options permit a
net-share settlement at the Company's option and do not result in a liability on
the consolidated balance sheet as of December 31, 2001.
The following table summarizes purchases under the stock purchase program
and the effect of the related put option premiums on the repurchase price.
<Table>
<Caption>
THIRD FOURTH YEAR TO DATE
QUARTER QUARTER ANNUAL MARCH 15, TOTAL
2001 2001 2001 2002 PROGRAM
million, except per share amounts ------- ------- ------ ------------ -------
Shares repurchased 2.2 -- 2.2 1.0 3.2
Total paid for shares repurchased $ 116 $ -- $ 116 $ 50 $ 166
Put premiums settled (5) (2) (7) (4) (11)
------ ---- ------ ------ ------
Total repurchase price $ 111 $ (2) $ 109 $ 46 $ 155
------ ---- ------ ------ ------
Average repurchase price per share $50.41 n/m $49.41 $46.25 $48.42
</Table>
44
OBLIGATIONS AND COMMITMENTS
Following is a summary of the Company's future payments on obligations as
of December 31, 2001.
<Table>
<Caption>
OBLIGATIONS BY PERIOD
-----------------------------------------
2-3 4-5 LATER
1 YEAR YEARS YEARS YEARS TOTAL
millions ------ ------ ----- ------ ------
Total debt* $708 $1,003 $432 $3,052 $5,195
Operating leases 72 135 105 263 575
Transportation and storage 23 37 19 100 179
Oil and gas activities -- 112 51 -- 163
</Table>
- ---------------
* Includes convertible debt that can be put back to the Company including: $620
million in 2002 and $30 million in 2004 related to the ZYP-CODES; and, $367
million in 2003 related to the Zero Coupon Convertible Debentures.
SYNTHETIC LEASES In November 1999, Anadarko entered into a build-to-suit lease
arrangement for its corporate office building in The Woodlands, Texas. The
development and acquisition of the property was financed by a special purpose
entity (SPE) sponsored by a financial institution. The lease balance to be
funded under this arrangement will not exceed $185 million. The SPE is not
consolidated in the Company's financial statements and, based on the initial
terms of the agreement, the Company has accounted for this arrangement as an
operating lease in accordance with Statement of Financial Accounting Standard
(SFAS) No. 13, "Accounting for Leases."
The initial lease term is five years, with up to seven one-year renewal
options. Monthly lease payments are based on the London interbank borrowing rate
applied against the lease balance and are expected to begin in 2002. Future
minimum lease payments under this lease are included in the table above. The
lease contains various covenants including covenants regarding the Company's
financial condition. Default under the lease, including violation of these
covenants, could require the Company to purchase the facility for a specified
amount, which approximates the lessor's original cost ($123 million funded as of
December 31, 2001). As of December 31, 2001, the Company was in compliance with
these covenants.
At the end of the lease term, the Company has an option to either purchase
the facility for the purchase option amount of the lease balance plus any
outstanding lease payments or to assist the SPE in the sale of the property. The
Company has provided a residual value guarantee for any deficiency if the
property is sold for less than the sale option amount ($104 million at December
31, 2001). In addition, the Company is entitled to any proceeds from a sale of
the property in excess of the purchase option amount.
In December 2000, the Company entered into a lease arrangement for an
office building in The Woodlands, Texas. The acquisition of the property was
financed by an SPE sponsored by a financial institution. The amount funded was
$48 million. The SPE is not consolidated in the Company's financial statements
and the Company has accounted for this arrangement as an operating lease in
accordance with SFAS No. 13.
The initial lease term is five years. Monthly lease payments, which began
in 2001, are based on the London interbank borrowing rate applied against the
$48 million lease balance. Future minimum lease payments under this lease are
included in the table above. The lease contains various covenants including
covenants regarding the Company's financial condition. Default under the lease,
including violation of these covenants, could require the Company to purchase
the facility for a specified amount, which approximates the lessor's original
cost ($48 million). As of December 31, 2001, the Company is in compliance with
these covenants.
At the end of the lease term, the Company has an option to either purchase
the facility for the purchase option amount of $48 million plus any outstanding
lease payments or to assist the SPE in the sale of the property. The Company has
provided a residual value guarantee for any deficiency if the property is sold
for less than the sale option amount ($39 million at December 31, 2001). In
addition, the Company is entitled to any proceeds from a sale of the property in
excess of the purchase option amount.
45
If, for either of these leases, the Company determines that it is probable
that the expected fair value of the property at the end of the lease term will
be less than the purchase option amount, the Company will accrue the expected
loss on a straight line basis over the remaining lease term. Currently,
management does not believe it is probable that the fair market value of either
of these properties will be less than the purchase option amount at the end of
the lease term.
OIL AND GAS ACTIVITIES As is common in the oil and gas industry, Anadarko has
various contractual commitments pertaining to exploration, development and
production activities. The amounts in the table reflect obligations and
commitments that are not included in the 2002 capital budget. Following is a
description of the Company's significant operating obligations and commitments
related to oil and gas activities.
Production Platform In December 2001, the Company signed a letter of intent
with El Paso Energy Partners (EPN) under which a floating production platform
for its Marco Polo discovery in Green Canyon Block 608 of the Gulf of Mexico
will be installed. EPN will construct the platform and processing facilities
that upon completion, expected in 2004, will be operated by Anadarko. The
proposed agreement provides that Anadarko will dedicate its production from
Green Canyon Block 608 and 11 other Green Canyon blocks to the processing
facilities. The proposed agreement will require a monthly demand charge of
slightly over $2 million for five years beginning at the time of project
completion and a processing fee based upon production. Anadarko will be entitled
to 25% of the net after tax cash proceeds from these facilities after payout, as
defined, is attained. The letter of intent does not contain any purchase
options, purchase obligations or value guarantees. The previous table does not
include any amounts related to this letter of intent.
Drilling and Work Commitments Anadarko has various work related commitments
for, among other things, drilling wells, obtaining and processing seismic and
fulfilling rig commitments. The above table includes drilling and work related
commitments of $163 million, comprised of $45 million in the United States, $53
million in Algeria, $37 million in Canada and $28 million in other international
locations. The commitments in Algeria are related primarily to exploration and
development contracts with SONATRACH, who is the beneficial owner of 5% of the
Company's outstanding common stock.
Sales Commitments In Canada, the Company has commitments to deliver gas and oil
under fixed price contracts. The gas and oil volumes to be delivered under these
contracts are as follows:
<Table>
<Caption>
COMMITMENTS BY PERIOD
--------------------------------------
2-3 4-5 LATER
1 YEAR YEARS YEARS YEARS TOTAL
------ ----- ----- ----- -----
NATURAL GAS
Volume -- million MMBtu 18 47 16 1 82
Price per MMBtu $2.16 $1.88 $1.70 $1.54 $1.90
CRUDE OIL
Volume -- million barrels* 2 2 -- -- 4
</Table>
- ---------------
* Price is NYMEX West Texas Intermediate minus $8 per barrel with a floor of
$14.40 per barrel and a ceiling of $17.24 per barrel for heavy oil delivered
at Hardisty Terminal.
GUARANTEES Anadarko is guarantor for certain obligations of its wholly-owned
and consolidated subsidiaries, which are included in the Consolidated Financial
Statements and Notes under Item 8 of this Form 10-K. In conjunction with the RME
merger, the Company guaranteed all of the outstanding debt of RME and its
subsidiaries, which is included in the consolidated debt of the Company. In
addition, the Company is guarantor for specific financial obligations of two
trona mining affiliates. The investments in these entities, which are not
consolidated subsidiaries, are accounted for using the equity method. The
Company has guaranteed a portion of certain Industrial Revenue Bonds, amounts
due under a revolving credit agreement and letters of credit required for
environmental surety bonds. The amount the Company would be obligated to pay
should the affiliates default on these obligations would be up to $8 million for
environmental surety bonds and $6 million in 2002 and $29 million after 2006 for
debt.
46
ENRON The recent financial problems of Enron have had no material adverse
effect on the Company. As of December 31, 2001, in connection with several
physical and financial contracts, the Company had $10 million, net, in accounts
payable to Enron North America and $1 million in accounts receivable from other
Enron affiliates. All contracts have been terminated by Anadarko under the terms
of the agreements, and $1 million has been charged to expense in 2001. The
Company, through purchase accounting entries for the Berkley acquisition, had
recorded market value liabilities on four contracts with Enron which were being
amortized over the terms of the contract. Upon termination of these contracts in
December 2001, the remaining liability of $12 million was no longer required and
was recorded as income in 2001.
For additional information on contracts and arrangements the Company enters into
from time to time see Item 7a. Quantitative and Qualitative Disclosures About
Market Risk of this Form 10-K and Note 5 -- Debt, Note 6 -- Financial
Instruments, Note 15 -- Lease Commitments, Note 16 -- Pension Plans, Other
Postretirement Benefits and Employee Savings Plans and Note 17 -- Contingencies
of the Notes to Consolidated Financial Statements under Item 8 of this Form
10-K.
OUTLOOK ON LIQUIDITY
Anadarko's net cash from operating activities in 2001 was $3.3 billion
compared to $1.5 billion in 2000 and $318 million in 1999. Commodity prices for
natural gas and crude oil rose dramatically in 2000 and decreased significantly
in the second half of 2001. The Company's original capital expenditure budget
for 2002 has been set at $2.0 billion. Cash flow from operations will vary
depending upon, among other things, actual commodity prices received throughout
the year. The Company intends to adjust capital expenditures to reflect changes
in its cash flow from operations. However, due to activities in progress at the
beginning of 2002 and the seasonal nature of drilling activity in Alaska and
Canada, the Company expects that a disproportionate amount of the 2002 capital
expenditure budget will be spent in the first and second quarters of the year.
As a result, it is likely that there will be an increase in debt early in the
year. Failure of prices to increase later in the year, as expected, could result
in increased borrowing throughout the year. Reduced fourth quarter activity in
2002 relative to 2001 could lead to higher working capital requirements and also
result in additional borrowing. The Company has a three-year stock buyback
program to purchase up to $1 billion in shares of Anadarko common stock.
Anticipated stock repurchases for 2002 are not included in the announced capital
expenditure budget and could require additional borrowing.
Anadarko believes that operating cash flow and existing or available credit
facilities will be adequate to meet its capital and operating requirements for
2002. The Company funds its day-to-day operating expenses and capital
expenditures from operating cash flows, supplemented as needed by short-term
borrowings of commercial paper, money market loans or credit facility
borrowings. To facilitate such borrowings, the Company has in place $750 million
in committed credit facilities, which are supplemented by various non-committed
credit lines that may be offered by certain banks from time to time at
then-quoted rates. It is the Company's policy to limit commercial paper
borrowing to levels that are fully back-stopped by unused balances from its
committed credit facilities. The Company may choose to refinance certain
portions of these short-term borrowings by issuing long-term debt in the public
or private debt markets. To facilitate such financings, the Company may file
shelf registrations in advance with the SEC. The Company continuously monitors
its debt position and coordinates its capital expenditure program with expected
cash flows and projected debt repayment schedules. The Company will continue to
evaluate funding alternatives, including property sales and additional
borrowing, to secure other funds for additional capital expenditures and stock
repurchases. At this time, Anadarko has no plans to issue common stock other
than through its Dividend Reinvestment and Stock Purchase Plan, through the
exercise of stock options or through the Company's Employee Savings Plan and
Employee Stock Ownership Plan equity funded contributions. See Regulatory
Matters and Additional Factors Affecting Business for additional information.
The Company's credit agreements allow for a maximum capitalization ratio of
60% debt, exclusive of the effect of any non-cash write-downs. As of December
31, 2001, Anadarko's capitalization ratio was 44% debt. While there is no
specific restriction on paying dividends, under the maximum debt capitalization
ratio retained earnings were not restricted as to the payment of dividends at
December 31, 2001. The amount of future common stock dividends will depend on
earnings, financial conditions, capital requirements and other factors, and will
be determined by the Board of Directors on a quarterly basis.
47
DIVIDENDS
In October 2001, the Board of Directors of Anadarko increased the quarterly
dividend on the Company's common stock from 5 cents to 7.5 cents per share.
In 2001, Anadarko paid $57 million in dividends to its common stockholders
(5 cents per share in the first, second and third quarters and 7.5 cents per
share in fourth quarter). In 2000, Anadarko paid $38 million in dividends to its
common stockholders (5 cents per share per quarter). The dividend amount in 1999
was $25 million (5 cents per share per quarter). Anadarko has paid a dividend to
its common stockholders continuously since becoming an independent company in
1986.
In 2001, 2000 and 1999, the Company also paid $7 million, $11 million and
$11 million, respectively, in preferred stock dividends. In 2002, the preferred
stock dividends are expected to be $6 million.
CRITICAL ACCOUNTING POLICIES
FINANCIAL STATEMENTS AND USE OF ESTIMATES The consolidated financial statements
include the accounts of Anadarko and its subsidiaries. All significant
intercompany transactions have been eliminated. The Company accounts for
investments in affiliated companies (20% to 50% owned) using the equity method
of accounting. The financial statements have been prepared in conformity with
generally accepted accounting principles appropriate in the circumstances. In
preparing financial statements, Management makes informed judgments and
estimates that affect the reported amounts of assets and liabilities as of the
date of the financial statements and affect the reported amounts of revenues and
expenses during the reporting period. Actual results may differ from these
estimates.
PROPERTIES AND EQUIPMENT The Company uses the full cost method of accounting
for exploration and development activities as defined by the SEC. Under this
method of accounting, the costs for unsuccessful, as well as successful,
exploration and development activities are capitalized as properties and
equipment. This includes any internal costs that are directly related to
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities.
The sum of net capitalized costs and estimated future development and
abandonment costs of oil and gas properties and mineral investments is amortized
using the unit-of-production method. All other properties are depreciated on the
straight-line basis over the useful life of the assets, which ranges from three
to 40 years.
PROVED RESERVES Proved oil and gas reserves are the estimated quantities of
natural gas, crude oil, condensate and NGLs that geological and engineering data
demonstrate with reasonable certainty can be recovered in future years from
known reservoirs under existing economic and operating conditions. Reserves are
considered "proved" if they can be produced economically as demonstrated by
either actual production or conclusive formation tests. Reserves which can be
produced economically through application of improved recovery techniques are
included in the "proved" classification when successful testing by a pilot
project or the operation of an installed program in the reservoir provides
support for the engineering analysis on which the project or program was based.
"Proved developed" oil and gas reserves can be expected to be recovered through
existing wells with existing equipment and operating methods.
The Company emphasizes that the volumes of reserves are estimates which, by
their nature, are subject to revision. The estimates are made using all
available geological and reservoir data as well as production performance data.
These estimates, made by the Company's engineers, are reviewed and revised,
either upward or downward, as warranted by additional data. Revisions are
necessary due to changes in assumptions based on, among other things, reservoir
performance, prices, economic conditions and governmental restrictions.
Decreases in prices, for example, may cause a reduction in some proved reserves
due to uneconomic conditions.
COSTS EXCLUDED Oil and gas properties include costs that are excluded from
capitalized costs being amortized. These amounts represent costs of investments
in unproved properties and major development projects. Anadarko excludes these
costs on a country-by-country basis until proved reserves are found or until it
is determined that the costs are impaired. All costs excluded are reviewed
quarterly to determine if impairment has occurred. Any impairment is transferred
to the costs to be amortized (the DD&A pool) or a charge is made against
earnings for those international operations where a reserve base has not yet
been
48
established. For international operations where a reserve base has not yet been
established, an impairment requiring a charge to earnings may be indicated
through evaluation of drilling results or relinquishing drilling rights. Costs
excluded for oil and gas properties are generally classified and evaluated as
significant or individually insignificant properties.
Significant properties, comprised primarily of costs associated with
domestic offshore blocks, Alaska, the Land Grant and other international areas,
are individually evaluated each quarter by the Company's exploration and
engineering staff. Non-producing leases are evaluated based on the progress of
the Company's exploration program to date. Exploration costs are transferred to
the DD&A pool upon completion of drilling individual wells. The Land Grant has
been in active evaluation to determine an exploration program for this acreage.
The Land Grant's mineral interests (both working and royalty interests) are
owned by the Company in perpetuity. All other significant properties are
evaluated over a five- to ten- year period, depending on the lease term.
Insignificant properties are comprised primarily of costs associated with
onshore properties in the United States and Canada. Non-producing leases are
impaired over a three- to five- year period based on the average lease period.
Exploration costs are transferred to the DD&A pool upon completion.
CAPITALIZED INTEREST SFAS No. 34, "Capitalization of Interest Costs," provides
standards for the capitalization of interest costs as part of the historical
cost of acquiring assets. FASB-Interpretation (FIN) No. 33 provides guidance for
the application of SFAS No. 34 to the full cost method of accounting for oil and
gas properties. Under FIN No. 33, costs of investments in unproved properties
and major development projects, on which DD&A expense is not currently taken and
on which exploration or development activities are in progress, qualify for
capitalization of interest. Capitalized interest is calculated by multiplying
the Company's weighted-average interest rate on debt by the amount of costs
excluded. Capitalized interest cannot exceed gross interest expense. As costs
excluded are transferred to the DD&A pool, the associated capitalized interest
is also transferred to the DD&A pool.
CEILING TEST Companies that use the full cost method of accounting for oil and
gas exploration and development activities are required to perform a ceiling
test each quarter. The full cost ceiling test is an impairment test prescribed
by SEC Regulation S-X Rule 4-10. The ceiling test is performed on a country-by-
country basis. The test determines a limit, or ceiling, on the book value of oil
and gas properties. That limit is basically the after tax present value of the
future net cash flows from proved crude oil and natural gas reserves. This
ceiling is compared to the net book value of the oil and gas properties reduced
by any related deferred income tax liability. If the net book value reduced by
the related deferred income taxes exceeds the ceiling, an impairment or non-cash
write down is required. A ceiling test impairment can give Anadarko a
significant loss for a particular period; however, future DD&A expense would be
reduced. Shown below is a summary of the ceiling test calculation and
description of the major components.
Ceiling Test Calculation
Present Value of Oil and Gas Properties (PV 10)
+ Costs Excluded
- Income Taxes
= Ceiling
Net Oil and Gas Properties and Equipment
- Deferred Income Tax Liability
= Net Investment
Ceiling - Net Investment = Cushion (Write-off) After Income Taxes
Present Value of Oil and Gas Properties (PV 10) Estimates of future net cash
flows from proved reserves of gas, oil, condensate and NGLs are made in
accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." The present value of oil and gas properties represents the
estimated future net cash flows from proved oil and gas reserves, discounted
using a prescribed 10% discount rate. Proved oil and gas reserves are estimated
quantities of natural gas, crude oil, condensate and NGLs that can be produced
economically as demonstrated by actual production or conclusive formation tests.
These estimates, which are determined by the Company's engineers, are reviewed
and revised as reservoir performance, prices and other
49
economic conditions change. Future net revenues are calculated based on
estimated production volumes generally using the oil and gas prices in effect on
the last day of the quarter, held flat for the life of the reserves. Future net
revenues are reduced by estimated future production and development costs based
on quarter-end cost levels, assuming continuation of existing economic
conditions.
Due to the volatility of commodity prices, the oil and gas prices on the
last day of the quarter significantly impact the calculation of the PV 10. At
year-end 2001, Anadarko's ceiling tests were based on NYMEX prices of $2.74 per
Mcf for natural gas and $19.78 per barrel for crude oil. The NYMEX prices are
adjusted by location and quality differentials, as appropriate, to determine
Anadarko's realized prices. The present value of future net cash flows does not
purport to be an estimate of the fair market value of Anadarko's proved
reserves. An estimate of fair value would also take into account, among other
things, anticipated changes in future prices and costs, the expected recovery of
reserves in excess of proved reserves and a discount factor more representative
of the time value of money and the risks inherent in producing oil and gas.
Costs Excluded Costs excluded are capitalized costs of investments in unproved
properties and major development projects. These costs are excluded from
capitalized costs being amortized through DD&A expense. Anadarko excludes all
costs until proved reserves are found or until it is determined that the costs
are impaired. When proved reserves are found, the decrease in costs excluded is
offset by an increase in PV 10; thereby generally increasing the ceiling. When
proved reserves are not found, the decrease in costs excluded is not offset by
an increase in PV 10; thereby decreasing the ceiling.
Income Taxes Future income taxes are based on the existing tax rates applied to
the difference between the total of the present value of the future net cash
flows plus costs excluded less the tax basis of the oil and gas properties. The
effect of tax loss carryforwards and credits is considered in determining income
taxes.
Net Oil and Gas Properties and Equipment Net oil and gas properties and
equipment are the capitalized costs related to oil and gas activities less the
accumulated DD&A. Under the full cost method of accounting the costs for
unsuccessful, as well as successful, exploration and development activities are
capitalized as properties and equipment. The net capitalized costs are
depreciated using the unit-of-production method. Net properties and equipment
increase due to capital expenditures or acquisitions and decrease due to DD&A
expense, property divestitures or ceiling test impairments.
Deferred Income Tax Liability Deferred income taxes related only to oil and gas
properties are included in the deferred income tax liability.
DERIVATIVE FINANCIAL INSTRUMENTS Anadarko uses derivative financial instruments
for various purposes and carefully monitors the credit worthiness of each
counter-party. Effective January 2001, derivative financial instruments utilized
to manage or reduce commodity price risk related to the Company's equity
production were accounted for under the provisions of SFAS No. 133 "Accounting
for Derivative Instruments and for Hedging Activities." Under this statement,
all derivatives are carried on the balance sheet at fair value. Realized
gains/losses and option premiums are recognized in the statement of income when
the underlying physical gas and oil production is sold. Accordingly, realized
derivative gains/losses are generally offset by similar changes in the realized
prices of the underlying physical gas and oil production. Realized derivative
gains/losses are reflected in the average sales price of the physical gas and
oil production.
Accounting for unrealized gains/losses is dependent on whether the
derivative financial instruments have been designated and qualify as part of a
hedging relationship. Derivative financial instruments may be designated as a
hedge of exposure to changes in fair values, cash flows or foreign currencies,
if certain conditions are met.
If the hedged exposure is to changes in fair value, the gains/losses on the
derivative financial instrument, as well as the offsetting losses/gains on the
hedged item, are recognized currently in earnings. Consequently, if gains/losses
on the derivative financial instrument and the related hedge item do not
completely offset, the difference (i.e., ineffective portion of the hedge) is
recognized currently in earnings.
If the hedged exposure is a cash flow exposure, the effective portion of
the gains/losses on the derivative financial instrument is reported as a
component of accumulated other comprehensive income and reclassified into
earnings in the same period or periods during which the hedged forecasted
transaction affects earnings. The ineffective portion of the gains/losses from
the derivative financial instrument, if any, as well as any
50
amounts excluded from the assessment of the cash flow hedges' effectiveness are
recognized currently in other (income) expense. Effective July 2001, the Company
implemented Derivatives Implementation Group Issue G20, "Cash Flow Hedges:
Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash
Flow Hedge," which provides guidance for assessing the effectiveness on total
changes in an option's cash flows rather than only on changes in the option's
intrinsic value. Time value changes were previously being recognized in current
earnings since the Company excluded time value changes from its assessment of
hedge effectiveness.
If the hedged exposure is a foreign currency exposure, the accounting is
similar to the accounting for fair value and cash flow hedges. Unrealized
gains/losses on derivative financial instruments that do not meet the conditions
to qualify for hedge accounting are recognized currently in earnings.
Derivative financial instruments, as well as physical delivery purchase and
sale contracts, utilized in the Company's energy trading activities and in the
management of price risk associated with the Company's firm transportation
keep-whole commitment (see Derivative Financial Instruments under Item 7a of
this Form 10-K) are accounted for under the mark-to-market accounting method
pursuant to Emerging Issues Task Force Issue 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities." Under this method,
the derivatives and physical delivery contracts are revalued in each accounting
period and premiums and unrealized gains/losses are recorded in the statement of
income and carried as assets or liabilities on the balance sheet.
The Company's derivative financial instruments associated with the
marketing and trading activities are generally either exchange traded or valued
by reference to a commodity that is traded in a liquid market. Valuation is
determined by reference to readily available public data. Option valuations are
based on the Black-Scholes option pricing model and verified against third-party
quotations. The fair value of the short-term portion of the firm transportation
keep-whole agreement is calculated with actively quoted natural gas basis
prices. Basis is the difference in value between gas at various delivery points
and the NYMEX gas futures contract price. Management believes that natural gas
basis price quotes beyond the next twelve months are not reliable indicators of
fair value due to decreasing liquidity. Accordingly, the fair value of the
long-term portion is estimated based on historical natural gas basis prices,
discounted at a 10% per year. Management also periodically evaluates the supply
and demand factors (such as expected drilling activity, anticipated pipeline
construction projects, expected changes in demand at pipeline delivery points,
etc.) that may impact the future market value of the firm transportation
capacity to determine if the estimated fair value should be adjusted.
NEW ACCOUNTING PRINCIPLES
SFAS No. 142 SFAS No. 142, "Goodwill and Other Intangible Assets," requires
discontinuing amortization of goodwill after year-end 2001 and requires that
goodwill be tested for impairment. The impairment test requires allocating
goodwill and all other assets and liabilities to business levels referred to as
reporting units. The fair value of each reporting unit that has goodwill is
determined and compared to the book value of the reporting unit. If the fair
value of the reporting unit is less than the book value (including goodwill)
then a second test is performed to determine the amount of the impairment.
If the second test is necessary, the fair value of the reporting unit's
individual assets and liabilities is deducted from the fair value of the
reporting unit. This difference represents the implied fair value of goodwill,
which is compared to the book value of the reporting unit's goodwill. Any excess
of the book value of goodwill over the implied fair value of goodwill is the
amount of the impairment.
The goodwill impairment test is performed annually, and also at interim
dates upon the occurrence of significant events. Significant events include: a
significant adverse change in legal factors or business climate; an adverse
action or assessment by a regulator; a more-likely-than-not expectation that a
reporting unit or significant portion of a reporting unit will be sold;
significant adverse trends in current and future oil and gas prices;
nationalization of any of the Company's oil and gas properties; or, significant
increases in a reporting unit's carrying value relative to its fair value.
The initial goodwill impairment test is required to be performed using an
effective date of January 1, 2002. The Company is in the process of assessing
the impact of adopting SFAS No. 142. Anadarko does not expect any initial
goodwill impairment.
51
SFAS No. 143 SFAS No. 143, "Accounting of Asset Retirement Obligations,"
requires the fair value of a liability for an asset retirement obligation to be
recorded in the period in which it is incurred and a corresponding increase in
the carrying amount of the related long-lived asset and will be effective for
the Company in January 2003. The Company is evaluating the impact of SFAS No.
143.
SFAS No. 144 SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," addresses financial accounting and reporting for the
impairment or disposal of long-lived assets. SFAS No. 144 requires that one
accounting model be used for long-lived assets to be disposed of by sale,
whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
The adoption of SFAS No. 144 as of January 2002 had no impact on the Company's
financial statements.
For additional information on the Company's accounting policies see Note 1 of
the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
REGULATORY MATTERS AND ADDITIONAL FACTORS AFFECTING BUSINESS
The Company has made in this report, and may from time to time otherwise
make in other public filings, press releases and discussions with Company
management, forward looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934
concerning the Company's operations, economic performance and financial
condition. These forward looking statements include information concerning
future production and reserves, schedules, plans, timing of development,
contributions from oil and gas properties, and those statements preceded by,
followed by or that otherwise include the words "believes," "expects,"
"anticipates," "intends," "estimates," "projects," "target," "goal," "plans,"
"objective," "should" or similar expressions or variations on such expressions.
For such statements, the Company claims the protection of the safe harbor for
forward looking statements contained in the Private Securities Litigation Reform
Act of 1995. Such statements are subject to various risks and uncertainties, and
actual results could differ materially from those expressed or implied by such
statements due to a number of factors in addition to those discussed below and
elsewhere in this Form 10-K and in the Company's other public filings, press
releases and discussions with Company management. Anadarko undertakes no
obligation to publicly update or revise any forward looking statements.
COMMODITY PRICING AND DEMAND Crude oil prices continue to be affected by
political developments worldwide, pricing decisions and production quotas of
OPEC and the volatile trading patterns in the commodity futures markets. Natural
gas prices also continue to be highly volatile. In periods of sharply lower
commodity prices, the Company may curtail production and capital spending
projects, as well as delay or defer drilling wells in certain areas because of
lower cash flows. Changes in crude oil and natural gas prices can impact the
Company's determination of proved reserves and the Company's calculation of the
standardized measure of discounted future net cash flows relating to oil and gas
reserves. In addition, demand for oil and gas in the U.S. and worldwide may
affect the Company's level of production.
Under the full cost method of accounting, a non-cash charge to earnings
related to the carrying value of the Company's oil and gas properties on a
country-by-country basis may be required when prices are low. Whether the
Company will be required to take such a charge depends on the prices for crude
oil and natural gas at the end of any quarter, as well as the effect of both
capital expenditures and changes to proved reserves during that quarter. While
this non-cash charge can give Anadarko a significant reported loss for the
period, future expenses for DD&A will be reduced.
ENVIRONMENTAL AND SAFETY The Company's oil and gas operations and properties
are subject to numerous federal, state and local laws and regulations relating
to environmental protection from the time oil and gas projects commence until
abandonment. These laws and regulations govern, among other things, the amounts
and types of substances and materials that may be released into the environment,
the issuance of permits in connection with exploration, drilling and production
activities, the release of emissions into the atmosphere, the discharge and
disposition of generated waste materials, offshore oil and gas operations, the
reclamation and abandonment of wells and facility sites and the remediation of
contaminated sites. In addition, these laws and
52
regulations may impose substantial liabilities for the Company's failure to
comply with them or for any contamination resulting from the Company's
operations.
Anadarko takes the issue of environmental stewardship very seriously and
works diligently to comply with applicable environmental and safety rules and
regulations. Compliance with such laws and regulations has not had a material
effect on the Company's operations or financial condition in the past. However,
because environmental laws and regulations are becoming increasingly more
stringent, there can be no assurances that such laws and regulations or any
environmental law or regulation enacted in the future will not have a material
effect on the Company's operations or financial condition.
For a description of certain environmental proceedings in which the Company
is involved, see Note 17 -- Contingencies of the Notes to Consolidated Financial
Statements under Item 8 of this Form 10-K.
EXPLORATION AND OPERATING RISKS The Company's business is subject to all of the
operating risks normally associated with the exploration for and production of
oil and gas, including blowouts, cratering and fire, any of which could result
in damage to, or destruction of, oil and gas wells or formations or production
facilities and other property and injury to persons. As protection against
financial loss resulting from these operating hazards, the Company maintains
insurance coverage, including certain physical damage, employer's liability,
comprehensive general liability and worker's compensation insurance. Although
Anadarko is not fully insured against all risks in its business, the Company
believes that the coverage it maintains is customary for companies engaged in
similar operations. The occurrence of a significant event against which the
Company is not fully insured could have a material adverse effect on the
Company's financial position.
DEVELOPMENT RISKS The Company is involved in several large development
projects. Key factors that may affect the timing and outcome of such projects
include: project approvals by joint venture partners; timely issuance of permits
and licenses by governmental agencies; manufacturing and delivery schedules of
critical equipment; and commercial arrangements for pipelines and related
equipment to transport and market hydrocarbons. In large development projects,
these uncertainties are usually resolved, but delays and differences between
estimated and actual timing of critical events are commonplace and may,
therefore, affect the forward-looking statements related to large development
projects.
DOMESTIC GOVERNMENTAL RISKS The domestic operations of the Company have been,
and at times in the future may be, affected by political developments and by
federal, state and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to governments
or governmental agencies, price or gathering rate controls and environmental
protection regulations.
FOREIGN OPERATIONS RISK The Company's operations in areas outside the U.S. are
subject to various risks inherent in foreign operations. These risks may
include, among other things, loss of revenue, property and equipment as a result
of hazards such as expropriation, war, insurrection and other political risks,
increases in taxes and governmental royalties, renegotiation of contracts with
governmental entities, changes in laws and policies governing operations of
foreign-based companies, currency restrictions and exchange rate fluctuations
and other uncertainties arising out of foreign government sovereignty over the
Company's international operations. The Company's international operations may
also be adversely affected by laws and policies of the United States affecting
foreign trade and taxation. To date, the Company's international operations have
not been materially affected by these risks.
COMPETITION The oil and gas business is highly competitive in the search for
and acquisition of reserves and in the gathering and marketing of oil and gas
production. The Company's competitors include the major oil companies,
independent oil and gas concerns, individual producers, gas marketers and major
pipeline companies, as well as participants in other industries supplying energy
and fuel to industrial, commercial and individual consumers.
OTHER Regulatory agencies in certain states and countries have authority to
issue permits for seismic exploration and the drilling of wells, regulate well
spacing, prevent the waste of oil and gas resources through proration and
regulate environmental matters.
Operations conducted by the Company on federal oil and gas leases must
comply with numerous regulatory restrictions, including various
nondiscrimination statutes. Additionally, certain operations must be conducted
pursuant to appropriate permits issued by the Bureau of Land Management and the
Minerals Management Service of the U.S. Department of the Interior. In addition
to the standard permit process,
53
federal leases and most international concessions require a complete
environmental impact assessment prior to authorizing an exploration or
development plan.
LEGAL PROCEEDINGS
General The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third-party contractors
alleging exposure to asbestos and benzene while working at a refinery in Corpus
Christi, Texas, which the Company sold in segments in 1987 and 1989. While the
ultimate outcome and impact on the Company cannot be predicted with certainty,
management believes that the resolution of these proceedings will not have a
material adverse effect on the consolidated financial position of the Company,
although results of operations and cash flow could be significantly impacted in
the reporting periods in which such matters are resolved.
For a description of certain legal proceedings in which the Company is
involved, see Legal Proceedings under Item 3 of this Form 10-K.
54
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
DERIVATIVE FINANCIAL INSTRUMENTS Anadarko's derivative commodity instruments
currently are comprised of futures, swaps and options contracts. The volume of
derivative commodity instruments utilized by the Company to hedge its market
price risk and in its energy trading operation can vary during the year within
the boundaries of its established policy guidelines. See Critical Accounting
Policies and Regulatory Matters and Additional Factors Affecting Business under
Item 7 and Note 1 -- Summary of Accounting Policies and Note 6 -- Financial
Instruments of the Notes to Consolidated Financial Statements under Item 8 of
this Form 10-K.
The majority of the derivatives into which the Company enters have terms of
less than 12 months. As of December 31, 2001, the Company had a net unrealized
gain of $7 million before taxes (gains of $9 million and losses of $2 million),
or $4 million after taxes, on derivative commodity instruments entered into to
hedge equity production recorded in accumulated other comprehensive income.
Other income for 2001, included $18 million of net gains related to derivative
instruments designated as cash flow hedges. These gains were primarily due to
the change in the time value of the option contracts that was excluded from the
assessment of hedge effectiveness. Based upon an analysis utilizing the actual
derivative contractual volumes and assuming a 10% increase in commodity prices,
the potential additional loss on these derivative commodity instruments would be
approximately $9 million.
As of December 31, 2001 and 2000, the Company had the following volumes
under derivative contracts related to its oil and gas producing
activities(non-trading activity):
DECEMBER 31, 2001
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MILLION MMBTU) ($ PER MMBTU) MILLIONS HEDGE ACCOUNTING
- ---------- ---------------- --------------- ------------------ ----------------- ----------------
NATURAL GAS
2002 2-way collar 2.3 3.00-5.00 $ 1 yes
2002 3-way collar 6.8 2.20-3.00-4.83 2 yes
2003 2-way collar 2.3 3.00-5.00 1 yes
2003 3-way collar 6.8 2.20-3.00-4.83 1 yes
2004 2-way collar 2.3 3.00-5.00 1 yes
2004 3-way collar 6.9 2.20-3.00-4.83 1 yes
2005 2-way collar 2.3 3.00-5.00 1 yes
2005 3-way collar 6.8 2.20-3.00-4.83 1 yes
2002 Calls sold 10.1 3.66 2 no
2002 Calls purchased 4.9 3.50 -- no
2003 Calls sold 7.4 3.18 (2) no
2003 Calls purchased 10.2 4.12 2 no
2004 Calls sold 0.7 2.95 -- no
2004 Calls purchased 0.7 2.95 -- no
---
Total $11
---
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MMBBLS) ($ PER BARREL) MILLIONS HEDGE ACCOUNTING
- ---------- ---------------- --------------- ------------------ ----------------- ----------------
CRUDE OIL
2002 Swaps 0.4 25.56 $ 2 yes
2002 3-way collar 3.3 19.11-23.33-30.51 6 yes
---
Total $ 8
---
</Table>
55
DECEMBER 31, 2000
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MILLION MMBTU) ($ PER MMBTU) MILLIONS HEDGE ACCOUNTING
- -------------- ---------------- --------------- ------------- ----------------- ----------------
NATURAL GAS
2001 Swaps 1.1 6.57 $ 10 yes
2001 2-way collar 74.7 4.14-9.24 (16) yes
2001 3-way collar 5.2 2.20-3.00-4.83 -- yes
2002 2-way collar 2.3 3.00-5.00 (1) yes
2002 3-way collar 6.8 2.20-3.00-4.83 (3) yes
2003 2-way collar 2.3 3.00-5.00 (1) yes
2003 3-way collar 6.8 2.20-3.00-4.83 (3) yes
2004 2-way collar 2.3 3.00-5.00 -- yes
2004 3-way collar 6.9 2.20-3.00-4.83 (1) yes
2005 2-way collar 2.3 3.00-5.00 -- yes
2005 3-way collar 6.8 2.20-3.00-4.83 (1) yes
2001 Calls sold 7.0 11.71 (3) no
2001 Calls sold 48.6 3.30 (133) no
2001 Calls purchased 49.5 3.31 136 no
2001 Puts sold 20.9 2.64 -- no
-----
Total $ (16)
-----
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MMBBLS) ($ PER BARREL) MILLIONS HEDGE ACCOUNTING
---------- ---------------- -------- -------------- ----------------- ----------------
CRUDE OIL
2001 2-way collar 4.3 19.32-23.77 $(11) yes
2001 3-way collar 6.6 18.03-21.00-25.98 (10) yes
2001 Puts sold 1.8 20.95 1 no
2001 Puts purchased 1.9 18.03 (5) no
-----
Total $(25)
-----
</Table>
- ---------------
MMBtu -- million British thermal units
MMBbls -- million barrels
* A "2-way collar" is a combination of options, a sold call and purchased put.
The purchased put establishes a minimum price (the "floor") and the sold call
establishes a maximum price (the "ceiling") the Company will receive for the
volumes under contract. A "3-way collar" is a combination of options, a sold
call, a purchased put and a sold put. The purchased put and sold put establish
a floating minimum price (the "floating floor") and the sold call establishes
a maximum price (the "ceiling") the Company will receive for the volumes under
contract.
Derivative financial instruments utilized in the Company's energy trading
activities and in the management of price risk associated with the Company's
firm transportation keep-whole commitment are accounted for under the
mark-to-market accounting method pursuant to Emerging Issues Task Force Issue
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities". Under this method, the derivatives and physical delivery purchase
and sale contracts are revalued in each accounting period and premiums and
unrealized gains/losses are immediately recorded in the statement of income and
carried as assets or liabilities on the balance sheet. Anadarko's energy
marketing and trading business is backed by the Company's substantial oil and
gas production and reserves. In the United States and Canada, the Company
purchases natural gas produced by other companies in those areas where the
Company has substantial production volumes. Third-party purchases allow the
Company to aggregate larger volumes of gas and attract larger, more creditworthy
customers, which in turn spreads the Company's relatively fixed overhead costs
over
56
more gas and can help reduce transportation costs. The Company does not engage
in market making practices nor does it trade in any non-energy-related
commodities. The marketing and trading business's risk position, most of the
time, is a net short position. Excluding the firm transportation keep-whole
agreement, essentially all of the Company's trading transactions have a term of
less than one year and most are less than three months. The keep-whole agreement
will be in effect until the earlier of each contract's expiration date or
February 2009. The derivative contracts entered into for trading purposes are
typically for terms of less than 12 months. As of December 31, 2001, the Company
had a net unrealized loss of $49 million (gains of $42 million and losses of $91
million) on derivative commodity instruments entered into for trading purposes.
Losses on derivative commodity instruments are offset by a net unrealized gain
of $66 million (gains of $82 million and losses of $16 million) on physical
contracts entered into for trading purposes. Based upon an analysis utilizing
the actual derivative contractual volumes and assuming a 10% increase in
underlying commodity prices, the potential loss on the derivative instruments
would be decreased by approximately $4 million.
The energy trading derivative contracts are primarily used to neutralize
fixed price exposure in physical delivery agreements and to generate profit on
or from exposure to changes in the market price of crude oil and natural gas. As
of December 31, 2001 and 2000, the Company had the following volumes under
derivative contracts related to its trading activity:
DECEMBER 31, 2001
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU) ($ PER MMBTU) MILLIONS
- ---------- ----------------- --------------- ------------- -----------------
NATURAL GAS
2002 Futures sold 23.8 3.34 $ 18
2002 Futures purchased 22.3 3.50 (21)
2002 Swaps 72.3 3.20 (42)
2002 Calls sold 8.5 3.07 1
2002 Calls purchased 12.8 4.09 1
2002 Puts sold 8.3 3.25 (7)
2002 Puts purchased 0.8 2.58 --
2003 Futures sold 1.2 3.51 --
2003 Futures purchased 0.3 3.36 --
2003 Swaps 12.2 3.12 --
----
Total $(50)
----
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MMBBLS) ($ PER BARREL) MILLIONS
- ---------- --------------- -------- -------------- -----------------
CRUDE OIL
2002 Futures sold 2.8 19.80 $ (1)
2002 Futures purchased 1.5 20.05 2
2002 Swaps 0.5 21.77 --
2002 Calls sold 0.4 29.50 --
----
Total $ 1
----
</Table>
57
DECEMBER 31, 2000
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU) ($ PER MMBTU) MILLIONS
- ---------- ----------------- --------------- ------------- -----------------
NATURAL GAS
2001 Futures sold 9.6 6.48 $(32)
2001 Futures purchased 9.0 7.82 19
2001 Swaps 23.0 5.31 77
2001 Calls sold 1.4 7.67 (2)
2001 Calls purchased 2.0 6.56 4
2001 Puts sold 3.2 7.93 (1)
2002 Swaps 0.5 2.08 (1)
----
Total $ 64
----
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MMBBLS) ($ PER BARREL) MILLIONS
- ---------- ----------------- -------- -------------- -----------------
CRUDE OIL
2001 Futures sold 1.8 27.40 $ 5
2001 Futures purchased 1.5 27.94 (5)
----
Total $ --
----
</Table>
RME was a party to several long-term firm gas transportation agreements
that supported their gas marketing program within the gathering, processing and
marketing (GPM) business segment, which was sold in 1999 to Duke Energy Field
Services, Inc. (Duke). Most of the GPM's firm long-term transportation contracts
were transferred to Duke in the GPM disposition. One contract was retained, but
is managed and operated by Duke. Anadarko is not responsible for the operations
of the contracts and does not utilize the associated transportation assets to
transport the Company's natural gas. As part of the GPM disposition, RME agreed
to pay Duke if transportation market values fall below the fixed contract
transportation rates, while Duke will pay RME if the transportation market
values exceed the contract transportation rates (keep-whole agreement). Net
payments from Duke for the year ended December 31, 2001 were $161 million.
Transportation contracts transferred to Duke in the GPM disposition and the
contract not transferred, all of which are included in the keep-whole agreement
with Duke, relate to various pipelines. This keep-whole agreement is accounted
for on a mark-to-market basis. This keep-whole agreement will be in effect until
the earlier of each contract's expiration date or February 2009. During 2001,
the Company recognized other income of $91 million ($26 million from the
agreement and $65 million from derivative financial instruments). As of December
31, 2001, other current liabilities included $27 million and other long-term
liabilities included $80 million related to this agreement. The future gain or
loss from this agreement cannot be accurately predicted.
Anticipated discounted and undiscounted liabilities for the firm
transportation keep-whole commitment at December 31, 2001 are as follows:
<Table>
<Caption>
MILLIONS UNDISCOUNTED DISCOUNTED
- -------- ------------ ----------
2002 $ 27 $ 27
2003 21 18
2004 27 22
2005 20 15
2006 19 12
Later years 23 13
---- ----
Total $137 $107
---- ----
</Table>
58
The Company may periodically use derivative financial instruments to reduce
its exposure under the keep-whole agreement to potential decreases in future
transportation market values. While the derivatives are intended to reduce the
Company's exposure to declines in transportation market rates, they also limit
the potential to benefit from market price increases. For the year ended
December 31, 2001, the Company recognized other income of $64 million on
derivative financial instruments related to transportation rates. At December
31, 2001, other current assets included $25 million of unrealized gains related
to this agreement. An analysis of these derivative financial instruments
determined that an adverse price movement would not have a material effect on
the financial position or results of operations of the Company. Due to decreased
liquidity, the use of derivative financial instruments to manage this risk is
generally limited to the forward twelve months only.
As of December 31, 2001 and 2000, the Company had the following volumes
under derivative contracts related to the firm transportation keep-whole
agreement:
DECEMBER 31, 2001
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU)* ($ PER MMBTU) MILLIONS
- ---------- --------------- ---------------- ------------- -----------------
NATURAL GAS
2002 Swaps 4.2 8.42 $25
</Table>
DECEMBER 31, 2000
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU)** ($ PER MMBTU) MILLIONS
- ---------- --------------- ----------------- ------------- -----------------
NATURAL GAS
2001 Swaps 13.4 9.08 $12
2001 Calls sold 0.9 9.84 --
---
Total $12
---
</Table>
- ---------------
* Represents 2% of the Company's total volumetric exposure under the keep-whole
agreement for 2002.
** Represents 6% of the Company's total volumetric exposure under the keep-whole
agreement for 2001.
For additional information regarding the Company's marketing and trading
portfolio and the firm transportation keep-whole agreement see Marketing
Strategies under Item 7 of this Form 10-K.
COMMON STOCK PURCHASE PROGRAM In July 2001, the Board of Directors authorized
the Company to purchase up to $1 billion in shares of Anadarko common stock. The
share purchases may be made from time to time, depending on market conditions.
Shares may be purchased either in the open market or through privately
negotiated transactions. The repurchase program does not obligate Anadarko to
acquire any specific number of shares and may be discontinued at any time.
During 2001, the Company purchased 2.2 million shares of common stock for $116
million. In January 2002, the Company purchased an additional 1 million shares
of common stock for $50 million.
To enhance the share repurchase program, Anadarko has sold put options to
independent third parties. These put options entitle the holder to sell shares
of Anadarko common stock to the Company on certain dates at specified prices.
During 2001, Anadarko sold put options for the purchase of a total of 5 million
shares of Anadarko common stock with a notional amount of $240 million. Put
options for 1 million shares were exercised, and put options for 2 million
shares expired unexercised in 2001. During 2001, premiums of $15 million were
received related to these put options and recorded as an increase to paid-in
capital. In January 2002, the Company entered into additional put options for 1
million shares of Anadarko common stock with a notional amount of $46 million
and received a $3 million premium. Put options for an additional 1 million
shares expired unexercised in 2002. The remaining put options for 2 million
shares will expire in March and July 2002, if not exercised. The put options
permit a net-share settlement at the Company's option and do not result in a
liability on the consolidated balance sheet as of December 31, 2001.
59
INTEREST RATE RISK Anadarko is also exposed to risk resulting from changes in
interest rates as a result of the Company's variable and fixed interest rate
debt. The Company believes the potential effect that reasonably possible near
term changes in interest rates may have on the fair value of the Company's
various debt instruments is not material.
FOREIGN CURRENCY RISK The Company's Canadian subsidiaries use the Canadian
dollar as their functional currency. The Company's other international
subsidiaries use the U.S. dollar as their functional currency. To the extent
that business transactions in these countries are not denominated in the
respective country's functional currency, the Company is exposed to foreign
currency exchange rate risk. In addition, in these subsidiaries, certain asset
and liability balances are denominated in currencies other than the subsidiary's
functional currency. These asset and liability balances are remeasured in the
preparation of the subsidiary's financial statements using a combination of
current and historical exchange rates, with any resulting remeasurement
adjustments included in net income during the period.
At December 31, 2001 and 2000, a Canadian subsidiary had $187 million and
$650 million, respectively, outstanding of fixed-rate notes and debentures
denominated in U.S. dollars. During 2001 and 2000, the Company recognized $25
million and $8 million, respectively, of non-cash losses before taxes associated
with the remeasurement of this debt. The potential foreign currency
remeasurement impact on earnings from a 10% change in the December 31, 2001
Canadian exchange rate would be about $20 million based on the outstanding debt
at December 31, 2001.
The Company periodically enters into foreign currency contracts to hedge
specific currency exposures from commercial transactions. As a result of the RME
merger transaction, the Company acquired foreign currency forward exchange
contracts with maturities through October 2004 and recorded a $4 million
deferred liability representing the fair value of these contracts. These
contracts were determined to be cash flow hedges of Anadarko Canada's future
U.S. dollar denominated hydrocarbon sales. This deferred liability will be
recognized in earnings when the contracts are settled. The unrealized loss on
foreign currency contracts excluding the $4 million unamortized deferred
liability at December 31, 2001 and 2000 was $6 million and $2 million,
respectively. Approximately $3 million of the after tax unrealized loss was
included in accumulated other comprehensive income as of December 31, 2001. No
portion of the balance is expected to be reclassified into earnings during 2002.
The following table summarizes the Company's open foreign currency positions at
December 31, 2001 and 2000:
<Table>
<Caption>
2001 2000
$ in millions, except foreign currency rates ------ ------
Notional amount -- US$ $ 70 $ 70
------ ------
Forward rate 1.36 1.36
Market rate 1.58 1.48
------ ------
Decrease in rate (0.22) (0.12)
------ ------
Fair value -- loss -- C$ $ 15 $ 8
------ ------
Fair value -- loss -- US$ $ 10 $ 6
------ ------
</Table>
At December 31, 2001 and 2000, the Company's Latin American subsidiaries
had foreign deferred tax liabilities denominated in the local currency
equivalent totaling $78 million and $98 million, respectively. During 2001 and
2000, the Company recognized tax benefits associated with remeasurement of these
deferred tax liabilities of $6 million and $9 million, respectively. In
conjunction with the sale of Latin American properties in 2001, the Company
indemnified a purchaser for the use of local tax losses denominated in the local
currency equivalent totaling $22 million. A gain of $1 million, before taxes,
was recognized related to the remeasurement of this liability and is included in
other (income) expense for the year ended December 31, 2001. The potential
foreign currency remeasurement impact on net earnings from a 10% change in the
year-end Latin American exchange rates would be approximately $9 million.
COMMODITY PRICE RISK As a result of low natural gas and oil prices at September
30, 2001, Anadarko's capitalized costs of oil and gas properties in the United
States, Canada and Argentina exceeded the ceiling limitation and the Company
recorded a $2.53 billion ($1.57 billion after taxes) non-cash write-down in the
third quarter of 2001. The pre-tax write-down is reflected as additional
accumulated depreciation, depletion and amortization. See Critical Accounting
Policies and Regulatory Matters and Additional Factors Affecting Business under
Item 7 of this Form 10-K.
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANADARKO PETROLEUM CORPORATION
INDEX
CONSOLIDATED FINANCIAL STATEMENTS
<Table>
<Caption>
PAGE
----
Report of Management 62
Independent Auditors' Report 63
Statement of Income, Three Years Ended December 31, 2001 64
Balance Sheet, December 31, 2001 and 2000 65
Statement of Stockholders' Equity, Three Years Ended
December 31, 2001 66
Statement of Comprehensive Income, Three Years Ended
December 31, 2001 67
Statement of Cash Flows, Three Years Ended December 31, 2001 68
Notes to Consolidated Financial Statements 69
Supplemental Quarterly Information 106
Supplemental Information on Oil and Gas Exploration and
Production Activities 107
</Table>
61
ANADARKO PETROLEUM CORPORATION
REPORT OF MANAGEMENT
The Management of Anadarko Petroleum Corporation is responsible for the
preparation and integrity of all information contained in the accompanying
consolidated financial statements. The financial statements have been prepared
in conformity with generally accepted accounting principles appropriate in the
circumstances. In preparing the financial statements, Management makes informed
judgments and estimates.
Management maintains and relies on the Company's system of internal
accounting controls. Although no system can ensure elimination of all errors and
irregularities, this system is designed to provide reasonable assurance that
assets are safeguarded, transactions are executed in accordance with
Management's authorization and accounting records are reliable as a basis for
the preparation of financial statements. This system includes the selection and
training of qualified personnel, an organizational structure providing
appropriate delegation of authority and division of responsibility, the
establishment of accounting and business policies for the Company and the
conduct of internal audits.
The Board of Directors pursues its responsibility for the consolidated
financial information through its Audit Committee, which is composed solely of
Directors who are not officers or employees of Anadarko. The Audit Committee
recommends to the Board of Directors the selection of independent auditors and
reviews their fee arrangements. The Audit Committee meets periodically with
Management, the internal auditors and the independent auditors to review that
each is carrying out its responsibilities. Both the internal and the independent
auditors have full and free access to the Audit Committee to discuss auditing
and financial reporting matters.
We believe that Anadarko's policies and procedures, including its system of
internal accounting controls, provide reasonable assurance that the financial
statements are prepared in accordance with the applicable securities rules and
regulations.
<Table>
/s/ JOHN N. SEITZ
John N. Seitz
President and Chief Executive Officer
/s/ MICHAEL E. ROSE
Michael E. Rose
Executive Vice President, Finance and
Chief Financial Officer
</Table>
62
ANADARKO PETROLEUM CORPORATION
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Anadarko
Petroleum Corporation and subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of income, stockholders' equity, comprehensive
income and cash flows for each of the years in the three-year period ended
December 31, 2001. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Anadarko
Petroleum Corporation and subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
financial instruments, and effective January 1, 2000, the Company changed its
method of accounting for foreign crude oil inventories.
/s/ KPMG LLP
Houston, Texas
January 31, 2002, except as to Note 18,
which is as of March 12, 2002
63
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF INCOME
<Table>
<Caption>
YEARS ENDED DECEMBER 31
---------------------------
2001 2000 1999
millions except per share amounts ------ ------ -------
REVENUES
Gas sales $2,893 $1,591 $ 353
Oil and condensate sales 1,380 948 247
Natural gas liquids sales 255 264 88
Marketing sales 3,776 2,637 1,016
Minerals and other 65 60 2
------ ------ -------
Total 8,369 5,500 1,706
------ ------ -------
COSTS AND EXPENSES
Marketing purchases 3,704 2,638 972
Operating expenses 716 438 179
Administrative and general 247 180 102
Depreciation, depletion and amortization 1,154 593 218
Other taxes 247 128 36
Provisions for doubtful accounts -- 23 --
Impairments related to oil and gas properties 2,546 50 24
Amortization of goodwill 73 31 --
------ ------ -------
Total 8,687 4,081 1,531
------ ------ -------
Operating Income (Loss) (318) 1,419 175
OTHER (INCOME) EXPENSE
Merger expenses 45 67 --
Interest expense 92 93 74
Other (income) expense (65) (167) (4)
------ ------ -------
Total 72 (7) 70
------ ------ -------
Income (Loss) Before Income Taxes (390) 1,426 105
INCOME TAXES
Income taxes (183) 602 62
Effect of change in Canadian income tax rate (31) -- --
------ ------ -------
Total (214) 602 62
------ ------ -------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE $ (176) $ 824 $ 43
------ ------ -------
Preferred Stock Dividends 7 11 11
------ ------ -------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS BEFORE
CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ (183) $ 813 $ 32
------ ------ -------
Cumulative Effect of Change in Accounting Principle 5 17 --
------ ------ -------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (188) $ 796 $ 32
------ ------ -------
PER COMMON SHARE
Net income (loss) -- before change in accounting
principle -- basic $(0.73) $ 4.42 $ 0.25
Net income (loss) -- before change in accounting
principle -- diluted $(0.73) $ 4.25 $ 0.25
Change in accounting principle -- basic $(0.02) $(0.09) $ --
Change in accounting principle -- diluted $(0.02) $(0.09) $ --
Net income (loss) -- basic $(0.75) $ 4.32 $ 0.25
Net income (loss) -- diluted $(0.75) $ 4.16 $ 0.25
Dividends $0.225 $ 0.20 $ 0.20
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -- BASIC 250 184 125
------ ------ -------
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -- DILUTED 250 193 126
------ ------ -------
</Table>
See accompanying notes to consolidated financial statements.
64
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEET
<Table>
<Caption>
DECEMBER 31
-----------------
2001 2000
millions ------- -------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 37 $ 199
Accounts receivable, net of allowance:
Customers 532 981
Others 486 395
Other current assets 146 319
------- -------
Total 1,201 1,894
------- -------
PROPERTIES AND EQUIPMENT
Original cost (includes unproved properties of $3,573 and
$2,898 as of December 31, 2001 and 2000, respectively) 20,088 15,843
Less accumulated depreciation, depletion and amortization 6,451 2,832
------- -------
Net properties and equipment -- based on the full cost
method of accounting for oil and gas properties 13,637 13,011
------- -------
OTHER ASSETS 503 368
------- -------
GOODWILL 1,534 1,348
Less accumulated amortization 104 31
------- -------
Goodwill, net of amortization 1,430 1,317
------- -------
$16,771 $16,590
------- -------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,132 $ 1,256
Accrued expenses 257 420
Current portion, notes and debentures 412 --
------- -------
Total 1,801 1,676
------- -------
LONG-TERM DEBT 4,638 3,984
------- -------
OTHER LONG-TERM LIABILITIES
Deferred income taxes 3,451 3,633
Other 516 511
------- -------
Total 3,967 4,144
------- -------
STOCKHOLDERS' EQUITY
Preferred stock, par value $1.00 per share
(2.0 million shares authorized, 0.1 million and 0.2
million shares issued as of December 31, 2001 and 2000,
respectively) 103 200
Common stock, par value $0.10 per share
(450.0 million shares authorized, 254.1 million and 253.3
million shares issued as of December 31, 2001 and 2000,
respectively) 25 25
Paid-in capital 5,336 5,303
Retained earnings 1,276 1,521
Treasury stock (2.2 million shares as of December 31, 2001) (116) --
Deferred compensation and ESOP (0.9 million and 1.1 million
shares as of December 31, 2001 and 2000, respectively) (96) (121)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of December 31, 2001 and 2000) (114) (145)
Accumulated other comprehensive income (loss)
Foreign currency translation adjustments (46) 3
Minimum pension liability (3) --
------- -------
Total (49) 3
------- -------
Total 6,365 6,786
------- -------
COMMITMENTS AND CONTINGENCIES -- --
------- -------
$16,771 $16,590
------- -------
</Table>
See accompanying notes to consolidated financial statements.
65
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<Table>
<Caption>
YEARS ENDED DECEMBER 31
--------------------------
2001 2000 1999
millions ------ ------ ------
PREFERRED STOCK
Balance at beginning of year $ 200 $ 200 $ 200
Preferred stock repurchased (97) -- --
------ ------ ------
Balance at end of year 103 200 200
------ ------ ------
COMMON STOCK
Balance at beginning of year 25 13 12
Common stock issued -- 12 1
------ ------ ------
Balance at end of year 25 25 13
------ ------ ------
PAID-IN CAPITAL
Balance at beginning of year 5,303 634 361
Common stock issued 51 4,592 267
Revaluation to market for Executives and Directors Benefits
Trust (31) 77 6
Preferred stock repurchased 13 -- --
------ ------ ------
Balance at end of year 5,336 5,303 634
------ ------ ------
RETAINED EARNINGS
Balance at beginning of year 1,521 764 757
Net income (loss) (181) 807 43
Dividends paid -- preferred (7) (11) (11)
Dividends paid -- common (57) (39) (25)
------ ------ ------
Balance at end of year 1,276 1,521 764
------ ------ ------
TREASURY STOCK
Balance at beginning of year -- -- --
Purchase of treasury stock (116) -- --
------ ------ ------
Balance at end of year (116) -- --
------ ------ ------
DEFERRED COMPENSATION AND ESOP
Balance at beginning of year (121) (8) (9)
Issuance of restricted stock (15) (82) (2)
Acquisition of ESOP -- (74) --
Amortization of restricted stock and release of ESOP shares 40 43 3
------ ------ ------
Balance at end of year (96) (121) (8)
------ ------ ------
EXECUTIVES AND DIRECTORS BENEFITS TRUST
Balance at beginning of year (145) (68) (62)
Revaluation to market 31 (77) (6)
------ ------ ------
Balance at end of year (114) (145) (68)
------ ------ ------
OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year 3 -- --
Foreign currency translation adjustments (49) 3 --
Minimum pension liability (3) -- --
------ ------ ------
Balance at end of year (49) 3 --
------ ------ ------
STOCKHOLDERS' EQUITY $6,365 $6,786 $1,535
------ ------ ------
</Table>
See accompanying notes to consolidated financial statements.
66
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
<Table>
<Caption>
YEARS ENDED DECEMBER 31
-----------------------
2001 2000 1999
millions ----- ---- ----
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $(188) $796 $ 32
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Unrealized gain (loss) on derivatives:
Cumulative effect of accounting change (net of taxes of $3
for the year ended December 31, 2001) (5) -- --
Reclassification of cumulative effect of accounting change
included in net income (net of taxes of $(2) for the
year ended December 31, 2001) 4 -- --
Unrealized gain during the period (net of taxes of $(19)
for the year ended December 31, 2001) 32 -- --
Reclassification adjustment for gains included in net
income (net of taxes of $18 for the year ended December
31, 2001) (31) -- --
----- ---- ----
Total unrealized gain (loss) on derivatives -- -- --
Foreign currency translation adjustments (49) 3 --
Minimum pension liability (net of taxes of $1 for the year
ended December 31, 2001) (3) -- --
----- ---- ----
Total (52) 3 --
----- ---- ----
COMPREHENSIVE INCOME (LOSS) $(240) $799 $ 32
----- ---- ----
</Table>
See accompanying notes to consolidated financial statements.
67
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<Table>
<Caption>
YEARS ENDED DECEMBER 31
------------------------
2001 2000 1999
millions ------- ------ -----
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) before cumulative effect of change in
accounting principle $ (176) $ 824 $ 43
Adjustments to reconcile net income (loss) before cumulative
effect of change in accounting principle to net cash
provided by operating activities:
Depreciation, depletion and amortization 1,155 594 220
Impairments related to oil and gas properties 2,546 50 24
Amortization of goodwill 73 31 --
Non-cash merger expenses 15 33 --
Interest expense -- zero coupon debentures 13 10 --
Deferred income taxes (319) 457 26
Provisions for doubtful accounts -- 23 --
Other non-cash items 122 (147) --
------- ------ -----
3,429 1,875 313
(Increase) decrease in accounts receivable 544 (703) (78)
Increase (decrease) in accounts payable and accrued expenses (534) 415 99
Other items -- net (118) (51) (16)
------- ------ -----
Net cash provided by operating activities 3,321 1,536 318
------- ------ -----
CASH FLOW FROM INVESTING ACTIVITIES
Additions to properties and equipment (3,316) (1,708) (680)
Acquisition costs, net of cash acquired (940) (53) --
Sales and retirements of properties and equipment 138 61 129
Proceeds from the sale of assets to be leased, net -- -- 15
------- ------ -----
Net cash used in investing activities (4,118) (1,700) (536)
------- ------ -----
CASH FLOW FROM FINANCING ACTIVITIES
Additions to debt 2,788 345 300
Retirements of debt (1,977) (321) (282)
Increase in accounts payable, banks 24 56 --
Dividends paid (64) (50) (36)
Retirement of preferred stock (84) -- --
Purchase of treasury stock (116) -- --
Issuance of common stock 49 288 264
------- ------ -----
Net cash provided by financing activities 620 318 246
------- ------ -----
EFFECT OF EXCHANGE RATE CHANGES ON CASH 15 -- --
------- ------ -----
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (162) 154 28
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 199 45 17
------- ------ -----
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 37 $ 199 $ 45
------- ------ -----
</Table>
See accompanying notes to consolidated financial statements.
68
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. SUMMARY OF ACCOUNTING POLICIES
GENERAL Anadarko Petroleum Corporation is engaged in the exploration,
development, production and marketing of natural gas, crude oil, condensate and
natural gas liquids (NGLs). The Company also engages in the hard minerals
business through non-operated joint ventures and royalty arrangements in several
coal, trona (natural soda ash) and industrial mineral mines. The terms
"Anadarko" and "Company" refer to Anadarko Petroleum Corporation and its
subsidiaries. The principal subsidiaries of Anadarko are: RME Petroleum Company;
RME Holding Company; Anadarko Canada Energy Ltd.; Anadarko Canada Corporation
(Anadarko Canada); RME Land Corp.; and, Anadarko Algeria Company, LLC (Anadarko
Algeria).
PRINCIPLES OF CONSOLIDATION AND USE OF ESTIMATES The consolidated financial
statements include the accounts of Anadarko and its subsidiaries. All
significant intercompany transactions have been eliminated. The Company accounts
for investments in affiliated companies (20% to 50% owned) using the equity
method of accounting. The financial statements have been prepared in conformity
with generally accepted accounting principles appropriate in the circumstances.
Certain amounts for prior years have been reclassified to conform to the current
presentation. In preparing financial statements, Management makes informed
judgments and estimates that affect the reported amounts of assets and
liabilities as of the date of the financial statements and affect the reported
amounts of revenues and expenses during the reporting period. Actual results may
differ from these estimates.
CHANGES IN ACCOUNTING PRINCIPLES In 2001, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, which provides guidance for
accounting for derivative instruments and hedging activities. The change was
effective January 2001 and the related cumulative adjustment to net income was a
decrease of $8 million ($5 million after taxes, or $0.02 per share) and the
cumulative adjustment to accumulated other comprehensive income was a decrease
of $8 million ($5 million after taxes).
Effective January 2000, the Company changed its method of accounting for
the carrying value of foreign crude oil inventories from market to cost. This
change was made as a result of a change in position on the carrying value of
inventories communicated by the United States Securities and Exchange Commission
(SEC). The related adjustment to net income was a decrease of $19 million ($17
million after taxes, or $0.09 per share) in 2000.
PROPERTIES AND EQUIPMENT The Company uses the full cost method of accounting
for exploration and development activities as defined by the SEC. Under this
method of accounting, the costs for unsuccessful, as well as successful,
exploration and development activities are capitalized as properties and
equipment. This includes any internal costs that are directly related to
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities. Gain or loss on
the sale or other disposition of oil and gas properties is not recognized,
unless the gain or loss would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas attributable to a
cost center.
The sum of net capitalized costs and estimated future development and
abandonment costs of oil and gas properties and mineral investments is amortized
using the unit-of-production method. All other properties are stated at original
cost and are depreciated on the straight-line basis over the useful life of the
assets, which ranges from three to 40 years. Properties and equipment carrying
values do not purport to represent replacement or market values.
Operating fees received related to the properties in which the Company owns
an interest are netted against operating expenses. Fees received in excess of
costs incurred are recorded as a reduction to the full cost pool.
69
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
COSTS EXCLUDED Oil and gas properties include costs that are excluded from
capitalized costs being amortized. These amounts represent costs of investments
in unproved properties and major development projects. Anadarko excludes these
costs on a country-by-country basis until proved reserves are found or until it
is determined that the costs are impaired. All costs excluded are reviewed
quarterly to determine if impairment has occurred. Any impairment is transferred
to the costs to be amortized (the depreciation, depletion and amortization
(DD&A) pool) or a charge is made against earnings for those international
operations where a reserve base has not yet been established. For international
operations where a reserve base has not yet been established, an impairment
requiring a charge to earnings may be indicated through evaluation of drilling
results or relinquishing drilling rights. Costs excluded for oil and gas
properties are generally classified and evaluated as significant or individually
insignificant properties.
Significant properties, comprised primarily of costs associated with
domestic offshore blocks, Alaska, the Land Grant and other international areas,
are individually evaluated each quarter by the Company's exploration and
engineering staff. Non-producing leases are evaluated based on the progress of
the Company's exploration program to date. Exploration costs are transferred to
the DD&A pool upon completion of drilling individual wells. The Land Grant has
been in active evaluation to determine an exploration program for this acreage.
The Land Grant's mineral interests (both working and royalty interests) are
owned by the Company in perpetuity. All other significant properties are
evaluated over a five- to ten-year period, depending on the lease term.
Insignificant properties are comprised primarily of costs associated with
onshore properties in the United States and Canada. Non-producing leases are
impaired over a three- to five-year period based on the average lease period.
Exploration costs are transferred to the DD&A pool upon completion.
CAPITALIZED INTEREST SFAS No. 34, "Capitalization of Interest Costs," provides
standards for the capitalization of interest costs as part of the historical
cost of acquiring assets. Financial Accounting Standards Board Interpretation
(FIN) No. 33 provides guidance for the application of SFAS No. 34 to the full
cost method of accounting for oil and gas properties. Under FIN No. 33, costs of
investments in unproved properties and major development projects, on which DD&A
expense is not currently taken and on which exploration or development
activities are in progress, qualify for capitalization of interest. Capitalized
interest is calculated by multiplying the Company's weighted-average interest
rate on debt by the amount of costs excluded. Capitalized interest cannot exceed
gross interest expense. As costs excluded are transferred to the DD&A pool, the
associated capitalized interest is also transferred to the DD&A pool.
CEILING TEST The Company limits, on a country-by-country basis, the capitalized
costs of proved oil and gas properties, net of accumulated DD&A and the related
deferred income taxes, to the estimated future net cash flows from proved oil
and gas reserves, generally using prices in effect at the end of the period held
flat for the life of production, discounted at 10%, net of related tax effects,
plus the cost of unevaluated properties and major development projects excluded
from the costs being amortized. If capitalized costs exceed this limit, the
excess is charged to expense and reflected as additional accumulated DD&A.
Proved oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and NGLs that geological and engineering data demonstrate
with reasonable certainty can be recovered in future years from known reservoirs
under existing economic and operating conditions. Reserves are considered proved
if they can be produced economically as demonstrated by either actual production
or conclusive formation tests. The Company emphasizes that the volumes of
reserves are estimates which, by their nature, are subject to revision. The
estimates are made using all available geological and reservoir data, as well as
production performance data. These estimates, made by the Company's engineers,
are reviewed and revised, either upward or downward, as warranted by additional
data. Revisions are necessary due to changes in assumptions based on, among
other things, reservoir performance, prices, economic conditions and
governmental restrictions. Decreases in prices, for example, may cause a
reduction in some proved reserves due to uneconomic conditions.
70
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
REVENUES Natural gas, oil and NGLs sales revenues are recorded using the sales
method, whereby the Company recognizes sales revenues based on the amount of
gas, oil and NGLs sold to purchasers on its behalf. Gas, oil and NGLs marketing
and gathering revenues are shown as marketing sales. Commodity trading positions
are marked to market, with the related gains and losses included in marketing
sales.
Effective January 2000, the Company adopted the provisions of the SEC Staff
Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements,"
which summarized the SEC staff's views in applying generally accepted accounting
principles to revenue recognition issues. As a result, marketing sales are shown
as revenues, offset by marketing purchases that are shown as costs and expenses,
rather than including only the margin as revenues.
DERIVATIVE FINANCIAL INSTRUMENTS Effective January 2001, derivative financial
instruments utilized to manage or reduce commodity price risk related to the
Company's equity production were accounted for under the provisions of SFAS No.
133. Under this statement, all derivatives are carried on the balance sheet at
fair value. Realized gains/losses and option premiums are recognized in the
statement of income when the underlying physical gas and oil production is sold.
Accordingly, realized derivative gains/losses are generally offset by similar
changes in the realized prices of the underlying physical gas and oil
production. Realized derivative gains/losses are reflected in the average sales
price of the physical gas and oil production.
Accounting for unrealized gains/losses is dependent on whether the
derivative financial instruments have been designated and qualify as part of a
hedging relationship. Derivative financial instruments may be designated as a
hedge of exposure to changes in fair values, cash flows or foreign currencies,
if certain conditions are met.
If the hedged exposure is to changes in fair value, the gains/losses on the
derivative financial instrument, as well as the offsetting losses/gains on the
hedged item, are recognized currently in earnings. Consequently, if gains/losses
on the derivative financial instrument and the related hedge item do not
completely offset, the difference (i.e., ineffective portion of the hedge) is
recognized currently in earnings.
If the hedged exposure is a cash flow exposure, the effective portion of
the gains/losses on the derivative financial instrument is reported as a
component of accumulated other comprehensive income and reclassified into
earnings in the same period or periods during which the hedged forecasted
transaction affects earnings. The ineffective portion of the gains/losses from
the derivative financial instrument, if any, as well as any amounts excluded
from the assessment of the cash flow hedges' effectiveness are recognized
currently in other (income) expense. Effective July 2001, the Company
implemented Derivatives Implementation Group Issue G20, "Cash Flow Hedges:
Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash
Flow Hedge," which provides guidance for assessing the effectiveness on total
changes in an option's cash flows rather than only on changes in the option's
intrinsic value. Time value changes were previously being recognized in current
earnings since the Company excluded time value changes from its assessment of
hedge effectiveness.
If the hedged exposure is a foreign currency exposure, the accounting is
similar to the accounting for fair value and cash flow hedges. Unrealized
gains/losses on derivative financial instruments that do not meet the conditions
to qualify for hedge accounting are recognized currently in earnings.
Derivative financial instruments, as well as physical delivery purchase and
sale contracts, utilized in the Company's energy trading activities and in the
management of price risk associated with the Company's firm transportation
keep-whole commitment are accounted for under the mark-to-market accounting
method pursuant to Emerging Issues Task Force Issue 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities." Under this
method, the derivatives and physical delivery contracts are revalued in each
accounting period and premiums and unrealized gains/losses are recorded in the
statement of income and carried as assets or liabilities on the balance sheet.
71
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
The Company's derivative financial instruments associated with the
marketing and trading activities are generally either exchange traded or valued
by reference to a commodity that is traded in a liquid market. Valuation is
determined by reference to readily available public data. Option valuations are
based on the Black-Scholes option pricing model and verified against third-party
quotations. The fair value of the short-term portion of the firm transportation
keep-whole agreement is calculated with actively quoted natural gas basis
prices, while the fair value of the long-term portion is estimated based on
historical natural gas basis prices. See Note 6.
Prior to the adoption of SFAS No. 133, derivative financial instruments
utilized to manage or reduce commodity price risk related to the Company's
equity production (with the exception of net written options) were accounted for
under the hedge or deferral method of accounting. Under this method, realized
gains/losses and option premiums were recognized in the statement of income when
the underlying physical oil and gas production was sold. Accordingly, realized
gains/losses were generally offset by similar changes in the realized prices of
the underlying physical oil and gas production. Realized derivative gains/losses
were reflected in the average sales price of the physical oil and gas
production. Margin deposits, deferred realized gains/losses and premiums were
included in other current assets or liabilities. Unrealized gains/losses were
not recorded.
Realized gains and losses resulting from the Company's interest rate swap
agreements were included in interest expense on a current basis. The swap
agreements effectively converted a portion of the Company's fixed interest rate
debt to variable interest rate debt. The Company's interest rate swap agreements
did not qualify for hedge accounting. Therefore, unrealized gains/losses were
recognized currently in earnings and reflected in other (income) expense. At
December 31, 2001, the Company had no outstanding interest rate swaps.
INVENTORIES Materials and supplies and company-produced commodity inventories
are stated at the lower of average cost or market. Inventories consisting of
commodities purchased from third parties in connection with the Company's
marketing and trading business are carried at fair value. Company produced
commodities, when sold from inventory, are charged to expense using the
average-cost method. Commodities purchased from third parties, when sold from
inventory, are charged to expense using market price.
GOODWILL Goodwill represents the excess of the purchase price over the
estimated fair value of the assets acquired and liabilities assumed in the
merger with Union Pacific Resources Group Inc., subsequently renamed RME Holding
Company (RME), and the acquisition of Berkley Petroleum Corp. (Berkley) (See
Note 2) and, through year-end 2001, was amortized on a straight-line basis over
20 years. The Company assessed the recoverability of goodwill by determining
whether the amortization of the goodwill balance over its remaining life could
be recovered through undiscounted future operating cash flows of the acquired
operation. The amount of goodwill impairment, if any, would have been measured
based on projected discounted future operating cash flows using a discount rate
reflecting the Company's average cost of funds. Effective January 2002, goodwill
is no longer amortized. See New Accounting Principles.
ENVIRONMENTAL CONTINGENCIES The Company accrues for losses associated with
environmental remediation obligations when such losses are probable and can be
reasonably estimated. Accruals for estimated losses from environmental
remediation obligations generally are recognized no later than the time of the
completion of the remedial feasibility study. These accruals are adjusted as
further information develops or circumstances change. Costs of future
expenditures for environmental remediation obligations are not discounted to
their present value. Recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed probable.
INCOME TAXES The Company files various U.S. federal, state and foreign income
tax returns. Deferred federal, state and foreign income taxes are provided on
all significant temporary differences, except for those
72
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
essentially permanent in duration, between the financial statement carrying
amounts of existing assets and liabilities and their respective tax bases.
CASH EQUIVALENTS The Company considers all highly liquid investments purchased
with an original maturity of three months or less to be cash equivalents.
STOCK-BASED COMPENSATION The Company accounts for stock-based compensation
under the intrinsic value method. Under this method, the Company records no
compensation expense for stock options granted to employees or directors when
the exercise price of options granted is equal to or above the fair market value
of Anadarko's common stock on the date of grant.
EARNINGS PER SHARE The Company's basic earnings (loss) per share (EPS) amounts
have been computed based on the average number of shares of common stock
outstanding for the period. Diluted EPS amounts include the effect of the
Company's outstanding stock options and performance-based stock awards under the
treasury stock method and outstanding put options under the reverse treasury
stock method. Diluted EPS amounts also include the net effect of the Company's
convertible debentures and Zero Yield Puttable Contingent Debt Securities
(ZYP-CODES) assuming the conversions occurred at the beginning of the year or
the date of issuance, if later.
NEW ACCOUNTING PRINCIPLES SFAS No. 141, "Business Combinations," requires that
the purchase method of accounting be used for all business combinations. SFAS
No. 141 also specifies criteria that must be met in order for intangible assets
acquired in a purchase method business combination to be recognized and reported
apart from goodwill. The adoption of SFAS No. 141 as of July 2001 had no impact
on the Company's financial statements.
SFAS No. 142, "Goodwill and Other Intangible Assets," requires
discontinuing amortization of goodwill after year-end 2001 and requires that
goodwill be tested for impairment. The impairment test requires allocating
goodwill and all other assets and liabilities to business levels referred to as
reporting units. The fair value of each reporting unit that has goodwill is
determined and compared to the book value of the reporting unit. If the fair
value of the reporting unit is less than the book value (including goodwill)
then a second test is performed to determine the amount of the impairment.
If the second test is necessary, the fair value of the reporting unit's
individual assets and liabilities is deducted from the fair value of the
reporting unit. This difference represents the implied fair value of goodwill,
which is compared to the book value of the reporting unit's goodwill. Any excess
of the book value of goodwill over the implied fair value of goodwill is the
amount of the impairment.
The goodwill impairment test is performed annually, and also at interim
dates upon the occurrence of significant events. Significant events include: a
significant adverse change in legal factors or business climate; an adverse
action or assessment by a regulator; a more-likely-than-not expectation that a
reporting unit or significant portion of a reporting unit will be sold;
significant adverse trends in current and future oil and gas prices;
nationalization of any of the Company's oil and gas properties; or, significant
increases in a reporting unit's carrying value relative to its fair value.
The initial goodwill impairment test is required to be performed using an
effective date of January 1, 2002. The Company is in the process of assessing
the impact of adopting SFAS No. 142. Anadarko does not expect any initial
goodwill impairment.
SFAS No. 143, "Accounting for Asset Retirement Obligations," requires the
fair value of a liability for an asset retirement obligation to be recorded in
the period in which it is incurred and a corresponding increase in the carrying
amount of the related long-lived asset and will be effective for the Company in
January 2003. The Company is evaluating the impact of SFAS No. 143.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," addresses financial accounting and reporting for the impairment or
disposal of long-lived assets. SFAS No. 144 requires that one
73
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. SUMMARY OF ACCOUNTING POLICIES (CONTINUED)
accounting model be used for long-lived assets to be disposed of by sale,
whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
The adoption of SFAS No. 144 as of January 2002 had no impact on the Company's
financial statements.
2. MERGER AND ACQUISITIONS
On July 14, 2000, the Company merged with Union Pacific Resources Group
Inc., subsequently renamed RME. Each share of common stock of RME issued and
outstanding was converted into 0.455 shares of Anadarko common stock. The merger
was treated as a tax-free reorganization and accounted for as a purchase
business combination under generally accepted accounting principles. Under this
method of accounting, the Company's historical operating results for periods
prior to the merger are the same as Anadarko's historical operating results. At
the date of the merger, the assets and liabilities of Anadarko remained based
upon their historical costs, and the assets and liabilities of RME were recorded
at their estimated fair market values.
The following is a calculation of the purchase price:
<Table>
<Caption>
millions, except per share amounts
Shares of common stock issued 114
Average of Anadarko stock price per share around the merger
announcement $35.58
------
Fair value of stock issued $4,060
Add: Fair value of vested RME employee stock options assumed
by Anadarko,
less common stock issuance costs 100
------
4,160
Add: Capitalized merger costs 143
------
Purchase price $4,303
------
</Table>
Capitalized merger costs relate primarily to severance and relocation costs
of RME employees ($84 million), professional fees directly related to the merger
($44 million) and other direct transaction costs ($15 million).
The following is the allocation of the purchase price to specific assets
and liabilities based on estimates of fair values and costs:
<Table>
<Caption>
millions
Current assets $ 661
Properties and equipment 8,243
Other assets 219
Goodwill 1,293
Current liabilities 969
Long-term debt 2,507
Deferred income taxes 2,465
Other long-term liabilities 315
------
Stockholders' equity $4,160
------
</Table>
The pro forma results for 2000 and 1999 are a result of combining the
statement of income of Anadarko with the statement of income of RME adjusted for
(1) certain costs that RME had expensed under the successful efforts method of
accounting that are capitalized under the full cost method of accounting; (2)
DD&A expense of RME calculated in accordance with the full cost method of
accounting applied to the
74
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2. MERGER AND ACQUISITIONS (CONTINUED)
adjusted basis of the properties acquired using the purchase method of
accounting; (3) decreases to interest expense for the capitalization of interest
on significant investments in unevaluated properties and major development
projects and partly offset by the revaluation of RME debt under the purchase
method of accounting, including the elimination of historical debt issuance
amortization costs; (4) issuance of Anadarko common stock and stock options
pursuant to the merger agreement; and, (5) the related income tax effects of
these adjustments based on the applicable statutory tax rates. It should be
noted that the pro forma results do not include any merger expenses.
The following table presents the unaudited pro forma results of the Company
as though the RME merger had occurred on January 1, 1999. Pro forma results are
not necessarily indicative of actual results.
<Table>
<Caption>
2000 1999
millions, except per share amounts ------ ------
Revenues $7,385 $4,442
Net income available to common stockholders $1,088 $ 328
Earnings per share -- basic $ 4.45 $ 1.37
Earnings per share -- diluted $ 4.30 $ 1.36
</Table>
Merger costs of $41 million and $67 million for the years ended December
31, 2001 and 2000, respectively, were expensed related to the RME merger. These
merger costs relate primarily to the issuance of stock for retention of
employees, deferred compensation, transition, integration, hiring and relocation
costs, vesting of restricted stock and stock options and retention bonuses.
In March 2001, Anadarko acquired Canadian based Berkley for C$11.40 per
share for an aggregate equity value of US$779 million plus the assumption of
US$236 million of debt. Goodwill recorded related to the Berkley acquisition was
$244 million. Merger costs of $3 million were expensed for the year ended
December 31, 2001 related to the Berkley acquisition.
In August 2001, the Company completed the acquisition of Gulfstream
Resources Canada Limited (Gulfstream). The Gulfstream shares were purchased for
C$2.65 per share, for a total value of US$118 million plus the assumption of
US$10 million of debt. Merger costs of $1 million were expensed for the year
ended December 31, 2001 related to the Gulfstream acquisition.
3. INVENTORIES
The major classes of inventories, which are included in other current
assets, are as follows:
<Table>
<Caption>
2001 2000
millions ---- ----
Materials and supplies $ 61 $44
Crude oil 22 20
Natural gas 18 15
---- ---
Total $101 $79
---- ---
</Table>
75
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
4. PROPERTIES AND EQUIPMENT
A summary of the original cost of properties and equipment by
classification follows:
<Table>
<Caption>
2001 2000
millions ------- -------
Oil and gas properties $18,047 $14,031
Mineral properties 1,212 1,213
Gathering facilities 295 194
General properties 534 405
------- -------
Total $20,088 $15,843
------- -------
</Table>
Oil and gas properties include costs of $3.57 billion and $2.90 billion at
December 31, 2001 and 2000, respectively, which were excluded from capitalized
costs being amortized. These amounts represent costs associated with unevaluated
properties and major development projects. At December 31, 2001, the Company's
investment in countries where reserves have not been established was $53
million.
During 2001, 2000 and 1999, the Company made provisions for impairments of
U.S. and international properties of $2.55 billion, $50 million and $24 million,
respectively, which were related to oil and gas properties. As a result of low
oil and gas prices at September 30, 2001, Anadarko's capitalized costs of oil
and gas properties primarily in the United States, Canada and Argentina exceeded
the ceiling limitation and the Company recorded a $2.53 billion ($1.57 billion
after taxes) non-cash write-down in the third quarter of 2001. The pre-tax
write-down is reflected as additional accumulated DD&A in the accompanying
balance sheet. The remaining 2001 impairment of $18 million related to
exploration activities in the United Kingdom and Ghana. In 2000, the Company
recorded international impairments of $50 million for exploration activities in
the United Kingdom, Tunisia and other international locations. International
impairments were recorded in 1999 for exploration activities in Eritrea and the
Faroe Islands totaling $24 million.
Total interest costs incurred during 2001, 2000 and 1999 were $301 million,
$193 million and $96 million, respectively. Of these amounts, the Company
capitalized $209 million, $100 million and $22 million during 2001, 2000 and
1999, respectively. Capitalized interest is included as part of the cost of oil
and gas properties. The interest rates for capitalization are based on the
Company's weighted average cost of borrowings used to finance the expenditures
applied to costs excluded.
In addition to capitalized interest, the Company also capitalized internal
costs of $178 million, $124 million and $81 million during 2001, 2000 and 1999,
respectively. These internal costs were directly related to exploration and
development activities and are included as part of the cost of oil and gas
properties.
76
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
5. DEBT
A summary of debt follows:
<Table>
<Caption>
2001 2000
-------------------------- --------------------------
PRINCIPAL CARRYING VALUE PRINCIPAL CARRYING VALUE
millions --------- -------------- --------- --------------
Notes Payable, Banks* $ 228 $ 228 $ 199 $ 199
Commercial Paper* 226 226 -- --
Long-term Portion of Capital Lease 9 9 12 12
8 1/4% Notes due 2001 -- -- 100 100
6.8% Debentures due 2002 88 88 250 247
6 3/4% Notes due 2003 73 73 100 100
5 7/8% Notes due 2003 83 83 100 100
6.5% Notes due 2005 170 164 200 192
7.375% Debentures due 2006 88 87 250 247
7% Notes due 2006 174 170 200 194
6.75% Notes due 2008 116 110 160 151
7.8% Debentures due 2008 11 11 150 150
7.3% Notes due 2009 85 82 160 156
6 3/4% Notes due 2011 950 910 -- --
7.05% Debentures due 2018 114 105 200 183
Zero Coupon Convertible Debentures due
2020 367 367 355 355
Zero Yield Puttable Contingent Debt
Securities due 2021 650 650 -- --
7.5% Debentures due 2026 112 105 200 188
7% Debentures due 2027 54 54 100 100
6.625% Debentures due 2028 17 17 100 100
7.15% Debentures due 2028 235 212 370 334
7.20% Debentures due 2029 135 135 300 300
7.95% Debentures due 2029 117 117 240 238
7 1/2% Notes due 2031 900 862 -- --
7.73% Debentures due 2096 61 61 100 100
7 1/4% Debentures due 2096 49 49 100 100
7.5% Debentures due 2096 83 75 150 138
------ ------ ------ ------
Total debt $5,195 5,050 $4,096 3,984
------ ------
Less current portion 412 --
------ ------
Total long-term debt $4,638 $3,984
------ ------
</Table>
- ---------------
* The average rates in effect December 31, 2001 and 2000 were 2.55% and 6.29%,
respectively, for the Notes Payable, Banks. The average rate in effect at
December 31, 2001 was 2.59% for Commercial Paper.
As a result of the RME merger transaction, the Company recorded $116
million of debt discount, representing the excess of the carrying value over the
fair value of the debt acquired. As a result of the 2001 financial restructuring
plan following the Berkley acquisition, an additional $40 million of debt
discount was recorded. The $145 million and $112 million of unamortized debt
discount as of December 31, 2001 and 2000, respectively, will be amortized over
the terms of the debt issues.
Anadarko has noncommitted lines of credit from several banks. The general
provisions of these lines of credit provide for Anadarko to borrow funds for
terms and rates offered from time to time by the banks. There are no fees
associated with these lines of credit.
77
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
5. DEBT (CONTINUED)
The Company has a commercial paper program that allows Anadarko to borrow
funds, at rates as offered, by issuing notes to investors for terms of up to 270
days.
At December 31, 2001, $1.16 billion of notes, debentures and securities
will mature or may be put to Anadarko within the next twelve months. In
accordance with SFAS No. 6, "Classification of Short-term Obligations Expected
to be Refinanced," $750 million of this amount is classified as long-term debt,
under the terms of Anadarko's Bank Credit Agreements. The remaining $412 million
is classified as short-term debt. At December 31, 2000, the 8 1/4% Notes due
2001 and notes payable to banks were classified as long-term debt in accordance
with SFAS No. 6, under the terms of Anadarko's Bank Credit Agreements.
In March 2000, Anadarko issued $345 million of Zero Coupon Convertible
Debentures due March 2020, with a face value at maturity of $690 million. The
debentures were issued at a discount and accrue interest at 3.50% annually until
reaching face value at maturity; however, interest will not be paid prior to
maturity. The debentures were issued at an initial conversion premium of 40% and
are convertible into common stock at the option of the holder at any time at a
fixed conversion rate. Holders have the right to require Anadarko to repurchase
their debentures at a specified price in March 2003, 2008 and 2013. The
debentures are redeemable at the option of Anadarko after three years. The net
proceeds from the offering were used to repay floating interest rate debt.
In March 2001, Anadarko issued $650 million of ZYP-CODES due 2021 to
qualified institutional buyers under Rule 144A and non-U.S. persons under
Regulation S. The debt securities were priced with a zero coupon, zero yield to
maturity and a conversion premium of 38%. The proceeds from the debt securities
were used initially to finance costs associated with the acquisition of Berkley.
Holders of the ZYP-CODES have the right to require Anadarko to purchase all or a
portion of their ZYP-CODES in March 2002, 2004, 2006, 2011 or 2016, at $1,000
per ZYP-CODES. Anadarko will pay the purchase price in cash. See Note 18.
In April 2001, Anadarko Finance Company, a wholly-owned finance subsidiary
of Anadarko, issued $1.30 billion in notes as part of the Company's financial
restructuring plan. This issuance was made up of $400 million of 6 3/4% Notes
due 2011 and $900 million of 7 1/2% Notes due 2031. In May 2001, Anadarko
Finance Company issued an additional $550 million of 6 3/4% Notes due 2011,
bringing the 6 3/4% Notes to an aggregate total of $950 million. The notes are
fully and unconditionally guaranteed by Anadarko. The notes were issued as part
of an exchange of securities for other Anadarko debt. The intercompany debt
resulting from these transactions is of a long-term investment nature;
therefore, foreign currency translation losses of $55 million for 2001 were
recorded as a component of other comprehensive income.
At December 31, 2001 and 2000, a Canadian subsidiary had $187 million and
$650 million, respectively, outstanding of fixed-rate notes and debentures
denominated in U.S. dollars. During 2001 and 2000, the Company recognized $25
million and $8 million, respectively, of non-cash losses before taxes associated
with the remeasurement of this debt.
In October 2001, the Company entered into a Revolving Credit Agreement and
a 364-Day Revolving Credit Agreement. Each agreement provides for a $225 million
principal amount and expires in 2004 and 2002, respectively. In October 2001,
Anadarko Canada, a wholly-owned subsidiary of Anadarko, entered into a 364-Day
Canadian Credit Agreement. The agreement provides for a US$300 million principal
amount and expires in 2002. The agreement is fully and unconditionally
guaranteed by Anadarko. Interest rates for these bank commitments are based on
either the prime rate, Fed Funds rate, London interbank borrowing rate or
Bankers' Acceptance rate. As of December 31, 2001, the Company had $69 million
outstanding under the Canadian Credit Agreement.
Total sinking fund and installment payments related to debt for the five
years ending December 31, 2006 are shown below. The payments related to the
redemption of the ZYP-CODES, 6.8% Debentures due 2002
78
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
5. DEBT (CONTINUED)
and a portion of the notes payable to banks are included in the amounts shown in
a manner consistent with the terms for repayment of the Anadarko's Bank Credit
Agreements.
<Table>
<Caption>
millions
2002 $412
2003* 381
2004* 225
2005 170
2006 262
</Table>
- ---------------
* Holders of the Zero Coupon Convertible Debentures due 2020 may put the
debentures to the Company in 2003 at the accrued value of $383 million.
Holders of the remaining $30 million of ZYP-CODES outstanding may put the
ZYP-CODES to the Company in 2004. See Note 18. These put options have not been
reflected in the table above.
6. FINANCIAL INSTRUMENTS
The following information provides the carrying value and estimated fair
value of the Company's financial instruments:
<Table>
<Caption>
CARRYING
AMOUNT FAIR VALUE
millions -------- ----------
2001
Cash and cash equivalents $ 37 $ 37
Total debt 5,050 5,170
Commodity derivative financial instruments (including firm
transportation
keep-whole agreement)
Asset 105 105
Liability (217) (217)
Foreign currency derivative financial instruments (10) (10)
2000
Cash and cash equivalents $ 199 $ 199
Total debt (including interest rate swaps) 3,984 3,980
Commodity derivative financial instruments (including firm
transportation
keep-whole agreement)
Asset 294 462
Liability (263) (398)
Foreign currency derivative financial instruments (4) (6)
</Table>
CASH AND CASH EQUIVALENTS The carrying amount reported on the balance sheet
approximates fair value.
DEBT The fair value of debt at December 31, 2001 and 2000 is the value the
Company would have to pay to retire the debt, including any premium or discount
to the debt holder for the differential between stated interest rate and
year-end market rate. The fair values are based on quoted market prices from
Standard and Poor's Bond Guide or Bloomberg L.P. and, where such quotes were not
available, on the average rate in effect at year-end.
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS The Company is exposed to price risk
from changing commodity prices. Management believes it is prudent to minimize
the variability in cash flows on a portion of its oil and gas production. To
meet this objective, the Company enters into various types of commodity
79
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
derivative financial instruments to manage fluctuations in cash flows resulting
from changing commodity prices. These instruments may include futures, swaps and
options and essentially all of these instruments have a term of less than one
year, with most having a term of less than three months. As of December 31,
2001, the Company had outstanding derivative financial instruments which hedged
4% of the Company's expected 2002 natural gas production and 8% of crude oil
production.
Anadarko also enters into commodity derivative financial instruments
(options, futures and swaps) for trading purposes with the objective of
generating profits from exposure to changes in the market price of natural gas
and crude oil. Commodity derivative financial instruments also provide a way to
meet customers' pricing requirements while achieving a price structure
consistent with the Company's overall pricing strategy. In addition, the Company
uses swap agreements to reduce exposure to losses on its firm transportation
keep-whole commitment with Duke Energy Field Services, Inc. (Duke).
Futures contracts are generally used to fix the price of expected future
oil and gas sales at major industry trading locations; e.g., Henry Hub,
Louisiana for gas and Cushing, Oklahoma for oil. Settlements of futures
contracts are guaranteed by the New York Mercantile Exchange or the
International Petroleum Exchange and have nominal credit risk. Swap agreements
are generally used to fix or float the price of oil and gas at the Company's
market locations. Swap agreements are also used to fix the price differential
between the price of gas at Henry Hub and various other market locations. Swap
agreements expose the Company to credit risk to the extent the counter-party is
unable to meet its monthly settlement commitment. The Company carefully monitors
the creditworthiness of each counter-party. In addition, the Company routinely
exercises its contractual right to net realized gains against realized losses in
settling with its swap counterparties. Options are generally used to fix a floor
and/or a ceiling price (a "collar") for the Company's expected future oil and
gas sales. The Company buys/sells options through exchanges as well as in the
over the counter market.
CASH FLOW HEDGES At December 31, 2001, the Company had option and swap
contracts in place to fix floor and/or ceiling prices on a portion of expected
future sales of equity gas and oil production. The Company has option contracts
to hedge its exposure to the variability in future cash flows associated with
sales of equity oil production that extend through December 2002 and associated
with sales of gas production that extend through December 2005. Swap agreements
to hedge the Company's exposure to the variability in future cash flows
associated with sales of equity oil production extend through December 2002. As
of December 31, 2001, the Company had a net unrealized gain of $7 million before
taxes (gains of $9 million and losses of $2 million), or $4 million after taxes,
on derivative commodity instruments entered into to hedge equity production
recorded in accumulated other comprehensive income. Other income for the year
ended December 31, 2001 included $18 million of net gains, primarily due to the
change in the time value of the option contracts, that was excluded from the
assessment of hedge effectiveness. Approximately $5 million of net gains in the
accumulated other comprehensive income balance as of December 31, 2001 are
expected to be reclassified into gas and oil sales during 2002 as the hedged
transactions occur.
80
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
As of December 31, 2001 and 2000, the Company had the following volumes
under derivative contracts related to its oil and gas producing activities
(non-trading activity):
DECEMBER 31, 2001
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MILLION MMBTU) ($ PER MMBTU) MILLIONS HEDGE ACCOUNTING
- ---------- ---------------- --------------- --------------- ----------------- ----------------
NATURAL GAS
2002 2-way collar 2.3 3.00-5.00 $ 1 yes
2002 3-way collar 6.8 2.20-3.00-4.83 2 yes
2003 2-way collar 2.3 3.00-5.00 1 yes
2003 3-way collar 6.8 2.20-3.00-4.83 1 yes
2004 2-way collar 2.3 3.00-5.00 1 yes
2004 3-way collar 6.9 2.20-3.00-4.83 1 yes
2005 2-way collar 2.3 3.00-5.00 1 yes
2005 3-way collar 6.8 2.20-3.00-4.83 1 yes
2002 Calls sold 10.1 3.66 2 no
2002 Calls purchased 4.9 3.50 -- no
2003 Calls sold 7.4 3.18 (2) no
2003 Calls purchased 10.2 4.12 2 no
2004 Calls sold 0.7 2.95 -- no
2004 Calls purchased 0.7 2.95 -- no
---
Total $11
---
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MMBBLS) ($ PER BARREL) MILLIONS HEDGE ACCOUNTING
- ---------- ---------------- -------- ----------------- ----------------- -----------------
CRUDE OIL
2002 Swaps 0.4 25.56 $2 yes
2002 3-way collar 3.3 19.11-23.33-30.51 6 yes
--
Total $8
--
</Table>
81
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
DECEMBER 31, 2000
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MILLION MMBTU) ($ PER MMBTU) MILLIONS HEDGE ACCOUNTING
- ----------- ---------------- --------------- -------------- ----------------- ----------------
NATURAL GAS
2001 Swaps 1.1 6.57 $ 10 yes
2001 2-way collar 74.7 4.14-9.24 (16) yes
2001 3-way collar 5.2 2.20-3.00-4.83 -- yes
2002 2-way collar 2.3 3.00-5.00 (1) yes
2002 3-way collar 6.8 2.20-3.00-4.83 (3) yes
2003 2-way collar 2.3 3.00-5.00 (1) yes
2003 3-way collar 6.8 2.20-3.00-4.83 (3) yes
2004 2-way collar 2.3 3.00-5.00 -- yes
2004 3-way collar 6.9 2.20-3.00-4.83 (1) yes
2005 2-way collar 2.3 3.00-5.00 -- yes
2005 3-way collar 6.8 2.20-3.00-4.83 (1) yes
2001 Calls sold 7.0 11.71 (3) no
2001 Calls sold 48.6 3.30 (133) no
2001 Calls purchased 49.5 3.31 136 no
2001 Puts sold 20.9 2.64 -- no
-----
Total $ (16)
-----
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY) QUALIFIES FOR
PERIOD INSTRUMENT TYPE* (MMBBLS) ($ PER BARREL) MILLIONS HEDGE ACCOUNTING
- ---------- ---------------- --------- ----------------- ----------------- ----------------
CRUDE OIL
2001 2-way collar 4.3 19.32-23.77 $(11) yes
2001 3-way collar 6.6 18.03-21.00-25.98 (10) yes
2001 Puts sold 1.8 20.95 1 no
2001 Puts purchased 1.9 18.03 (5) no
----
Total $(25)
----
</Table>
- ---------------
MMBtu -- million British thermal units
MMBbls -- million barrels
* A "2-way collar" is a combination of options, a sold call and purchased put.
The purchased put establishes a minimum price (the "floor") and the sold call
establishes a maximum price (the "ceiling") the Company will receive for the
volumes under contract. A "3-way collar" is a combination of options, a sold
call, a purchased put and a sold put. The purchased put and sold put establish
a floating minimum price (the "floating floor") and the sold call establishes
a maximum price (the "ceiling") the Company will receive for the volumes under
contract.
82
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
FAIR VALUE HEDGE The Company had a swap agreement in place to convert a gas
contract from a fixed price to a market sensitive price. The term of this swap
agreement, as well as the underlying gas contract, expired October 31, 2001.
TRADING ACTIVITY As of December 31, 2001 and 2000, the Company had the
following volumes under derivative contracts related to its trading activity:
DECEMBER 31, 2001
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU) ($ PER MMBTU) MILLIONS
- ---------- --------------- --------------- ------------- -----------------
NATURAL GAS
2002 Futures sold 23.8 3.34 $ 18
2002 Futures purchased 22.3 3.50 (21)
2002 Swaps 72.3 3.20 (42)
2002 Calls sold 8.5 3.07 1
2002 Calls purchased 12.8 4.09 1
2002 Puts sold 8.3 3.25 (7)
2002 Puts purchased 0.8 2.58 --
2003 Futures sold 1.2 3.51 --
2003 Futures purchased 0.3 3.36 --
2003 Swaps 12.2 3.12 --
----
Total $(50)
----
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MMBBLS) ($ PER BARREL) MILLIONS
- ---------- --------------- -------- -------------- -----------------
CRUDE OIL
2002 Futures sold 2.8 19.80 $(1)
2002 Futures purchased 1.5 20.05 2
2002 Swaps 0.5 21.77 --
2002 Calls sold 0.4 29.50 --
---
Total $ 1
---
</Table>
83
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
DECEMBER 31, 2000
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU) ($ PER MMBTU) MILLIONS
- ----------- ----------------- --------------- ------------- -----------------
NATURAL GAS
2001 Futures sold 9.6 6.48 $(32)
2001 Futures purchased 9.0 7.82 19
2001 Swaps 23.0 5.31 77
2001 Calls sold 1.4 7.67 (2)
2001 Calls purchased 2.0 6.56 4
2001 Puts sold 3.2 7.93 (1)
2002 Swaps 0.5 2.08 (1)
----
Total $ 64
----
</Table>
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MMBBLS) ($ PER BARREL) MILLIONS
- ----------- ----------------- -------- -------------- -----------------
CRUDE OIL
2001 Futures sold 1.8 27.40 $ 5
2001 Futures purchased 1.5 27.94 (5)
----
Total $ --
----
</Table>
FIRM TRANSPORTATION KEEP-WHOLE AGREEMENT RME was a party to several long-term
firm gas transportation agreements that supported their gas marketing program
within their gathering, processing and marketing (GPM) business segment, which
was sold in 1999 to Duke. Most of the GPM's firm long-term transportation
contracts were transferred to Duke in the GPM disposition. One contract was
retained, but is managed and operated by Duke. Anadarko is not responsible for
the operations of the contracts and does not utilize the associated
transportation assets to transport the Company's natural gas. As part of the GPM
disposition, RME agreed to pay Duke if transportation market values fall below
the fixed contract transportation rates, while Duke will pay RME if the
transportation market values exceed the contract transportation rates
(keep-whole agreement). Transportation contracts transferred to Duke in the GPM
disposition and the contract not transferred, all of which are included in the
keep-whole agreement with Duke, relate to various pipelines. This keep-whole
agreement will be in effect until the earlier of each contract's expiration date
or February 2009. The Company may periodically use derivative financial
instruments to manage the price risk associated with this agreement. This
keep-whole agreement and any oil and gas derivative financial instruments are
accounted for on a mark-to-market basis. The Company recognized other income of
$91 and $175 million during 2001 and 2000, respectively. As of December 31, 2001
and 2000, other current assets included $25 million and $129 million, accounts
payable included $27 million and zero and other long-term liabilities included
$80 million and $89 million, respectively, related to the keep-whole agreement
and associated derivative financial instruments.
The fair value of the short-term portion of the firm transportation
keep-whole agreement is calculated with actively quoted natural gas basis
prices. Basis is the difference in value between gas at various delivery points
and the NYMEX gas futures contract price. Management believes that natural gas
basis price quotes beyond the next twelve months are not reliable indicators of
fair value due to decreasing liquidity. Accordingly, the fair value of the
long-term portion is estimated based on historical natural gas basis prices,
discounted at 10% per year. Management also periodically evaluates the supply
and demand factors (such as
84
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
expected drilling activity, anticipated pipeline construction projects, expected
changes in demand at pipeline delivery points, etc.) that may impact the future
market value of the firm transportation capacity to determine if the estimated
fair value should be adjusted.
Anticipated discounted and undiscounted liabilities for the firm
transportation keep-whole commitment at December 31, 2001 are as follows:
<Table>
<Caption>
UNDISCOUNTED DISCOUNTED
millions ------------ ----------
2002 $ 27 $ 27
2003 21 18
2004 27 22
2005 20 15
2006 19 12
Later years 23 13
---- ----
Total $137 $107
---- ----
</Table>
As of December 31, 2001 and 2000, the Company had the following volumes
under derivative contracts related to the firm transportation keep-whole
agreement:
DECEMBER 31, 2001
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU)* ($ PER MMBTU) MILLIONS
- ---------- --------------- ---------------- ------------- -----------------
NATURAL GAS
2002 Swaps 4.2 8.42 $25
</Table>
DECEMBER 31, 2000
<Table>
<Caption>
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU)** ($ PER MMBTU) MILLIONS
- ---------- --------------- ----------------- ------------- -----------------
NATURAL GAS
2001 Swaps 13.4 9.08 $12
2001 Calls sold 0.9 9.84 --
---
Total $12
---
</Table>
- ---------------
* Represents 2% of the Company's total volumetric exposure under the keep-whole
agreement for 2002.
** Represents 6% of the Company's total volumetric exposure under the keep-whole
agreement for 2001.
INTEREST RATE SWAPS Interest rate swap agreements were entered into to offset a
portion of the effect of the Company's fixed rate long-term debt. In 1999,
Anadarko entered into a 29.5 year swap agreement with a notional value of $200
million whereby the Company received a fixed interest rate and paid a floating
interest rate indexed to the 3-month London interbank borrowing rate. The swap
agreement was cancelled in March 2001 at no cost to the Company. During 1996,
Anadarko entered into a 10-year swap agreement with a notional value of $100
million whereby the Company received a fixed interest rate and paid a floating
interest rate indexed to the 3-month London interbank borrowing rate. This
agreement was terminated in May 2001 at no cost to the Company.
85
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
6. FINANCIAL INSTRUMENTS (CONTINUED)
FOREIGN CURRENCY RISK Anadarko's Canadian subsidiaries use the Canadian dollar
as their functional currency. The Company's other international subsidiaries use
the U.S. dollar as their functional currency. To the extent that business
transactions in these countries are not denominated in the respective country's
functional currency, the Company is exposed to foreign currency exchange rate
risk. In addition, in these subsidiaries, certain asset and liability balances
are denominated in currencies other than the subsidiary's functional currency.
These asset and liability balances are remeasured for the preparation of the
subsidiary's financial statements using a combination of current and historical
exchange rates, with any resulting remeasurement adjustments included in net
income during the period.
The Company periodically enters into foreign currency contracts to hedge
specific currency exposures from commercial transactions. As a result of the RME
merger transaction, the Company acquired foreign currency forward exchange
contracts with maturities through October 2004 and recorded a $4 million
deferred liability representing the fair value of these contracts. These
contracts were determined to be cash flow hedges of Anadarko Canada's future
U.S. dollar denominated hydrocarbon sales. This deferred liability will be
recognized in earnings when the contracts are settled. The unrealized loss on
foreign currency contracts excluding the $4 million unamortized deferred
liability at December 31, 2001 and 2000 was $6 million and $2 million,
respectively. Approximately $3 million of the after tax unrealized loss was
included in accumulated other comprehensive income as of December 31, 2001. No
portion of the balance is expected to be reclassified into earnings during 2002.
The following table summarizes the Company's open foreign currency positions at
December 31, 2001 and 2000:
<Table>
<Caption>
2001 2000
------ ------
$ in millions, except foreign currency rates
Notional amount -- US$ $ 70 $ 70
------ ------
Forward rate 1.36 1.36
Market rate 1.58 1.48
------ ------
Decrease in rate (0.22) (0.12)
------ ------
Fair value -- loss -- C$ $ 15 $ 8
------ ------
Fair value -- loss -- US$ $ 10 $ 6
------ ------
</Table>
At December 31, 2001 and 2000, the Company's Latin American subsidiaries
had foreign deferred tax liabilities denominated in the local currency
equivalent totaling $78 million and $98 million, respectively. During 2001 and
2000, the Company recognized tax benefits associated with remeasurement of these
deferred tax liabilities of $6 million and $9 million, respectively. In
conjunction with the sale of Latin American properties in 2001, the Company
indemnified a purchaser for the use of local tax losses denominated in local
currency equivalent totaling $22 million. A gain of $1 million, before taxes,
was recognized related to the remeasurement of this liability and is included in
other (income) expense for the year ended December 31, 2001.
7. PREFERRED STOCK
In May 1998, Anadarko issued $200 million of 5.46% Series B Cumulative
Preferred Stock in the form of two million Depositary Shares, each Depositary
Share representing 1/10th of a share of the 5.46% Series B Cumulative Preferred
Stock. The preferred stock has no stated maturity and is not subject to a
sinking fund or mandatory redemption. The shares are not convertible into other
securities of the Company.
86
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
7. PREFERRED STOCK (CONTINUED)
Anadarko has the option to redeem the shares at $100 per Depositary Share
on or after May 15, 2008. Holders of the shares are entitled to receive, when,
and as declared by the Board of Directors, cumulative cash dividends at an
annual dividend rate of $5.46 per Depositary Share.
During 2001, Anadarko repurchased $97 million of preferred stock. The
resulting gain of $13 million was recorded to paid-in capital. During 2001, 2000
and 1999, dividends of $54.60 per share (equivalent to $5.46 per Depositary
Share) were paid to holders of preferred stock.
8. COMMON STOCK AND STOCK OPTIONS
Following is a schedule of the changes in the Company's shares of common
stock:
<Table>
<Caption>
2001 2000 1999
millions ---- ---- ----
SHARES OF COMMON STOCK ISSUED
Beginning of year 253 130 122
Issuance of common stock -- 114 7
Exercise of stock options 1 6 1
Issuance of restricted stock -- 2 --
Issuance of shares for unearned employee stock ownership
plan -- 1 --
--- --- ---
End of year 254 253 130
--- --- ---
SHARES OF COMMON STOCK HELD IN TREASURY
Beginning of year -- -- --
Purchase of treasury stock 2 -- --
--- --- ---
End of year 2 -- --
--- --- ---
SHARES OF COMMON STOCK HELD FOR UNEARNED EMPLOYEE STOCK
OWNERSHIP PLAN
Beginning of year 1 -- --
Issuance of stock -- 1 --
--- --- ---
End of year 1 1 --
--- --- ---
SHARES OF COMMON STOCK HELD FOR EXECUTIVES AND DIRECTORS
BENEFITS TRUST
Beginning of year 2 2 2
--- --- ---
End of year 2 2 2
--- --- ---
SHARES OF COMMON STOCK OUTSTANDING AT END OF YEAR 249 250 128
--- --- ---
</Table>
In the fourth quarter of 2001, dividends of 7.5 cents per share were paid
to holders of common stock. For the first, second and third quarters of 2001 and
for each quarter of 2000 and 1999, dividends of 5 cents per share were paid to
holders of common stock. The Company's credit agreements allow for a maximum
capitalization ratio of 60% debt, exclusive of the effect of any non-cash
writedowns. While there is no specific restriction on paying dividends, under
the maximum debt capitalization ratio retained earnings were not restricted as
to the payment of dividends at December 31, 2001. Under the most restrictive
provisions of the various credit agreements in effect at December 31, 2000,
retained earnings were not restricted as to the payment of dividends at December
31, 2000.
On July 13, 2000, the stockholders of Anadarko approved an increase in the
authorized number of Anadarko common shares from 300 million to 450 million. On
July 14, 2000, each share of common stock of RME issued and outstanding was
converted into 0.455 shares of Anadarko common stock with approximately 114
million shares issued to the stockholders of RME.
87
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
8. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
In May 1999, Anadarko issued 6 million shares of common stock. Aggregate
proceeds from the offering were approximately $241 million after all expenses.
The Anadarko Dividend Reinvestment and Stock Purchase Plan (DRIP) offers
the opportunity to reinvest dividends and provides an alternative to traditional
methods of buying, holding and selling Anadarko common stock. The DRIP provides
the Company with a means of raising additional capital for general corporate
purposes. In September 1999, the Company filed a registration statement with the
SEC that permits the issuance of up to 4.5 million additional shares of common
stock under the DRIP.
Under the Anadarko Stockholders Rights Plan, Rights were attached
automatically to each outstanding share of common stock in November 1998. Each
Right, at the time it becomes exercisable and transferable apart from the common
stock, entitles stockholders to purchase from the Company 1/1000th of a share of
a new series of junior participating preferred stock at an exercise price of
$175. The Right will be exercisable only if a person or group acquires 15% or
more of common stock or announces a tender offer or exchange offer, the
consummation of which would result in ownership by a person or group of 15% or
more of the common stock. The Board of Directors may elect to exchange and
redeem the Rights. The Rights expire in November 2008.
In July 2001, the Board of Directors authorized the Company to purchase up
to $1 billion in shares of Anadarko common stock. The share purchases may be
made from time to time, depending on market conditions. Shares may be purchased
either in the open market or through privately negotiated transactions. The
repurchase program does not obligate Anadarko to acquire any specific number of
shares and may be discontinued at any time. During 2001, the Company purchased
2.2 million shares of common stock for $116 million. In January 2002, the
Company purchased an additional 1 million shares of common stock for $50
million. During 2000 and 1999, the Company acquired treasury stock only as a
result of stock option exercises, restricted stock transactions or buyback of
shares, which were unsolicited from stockholders.
To enhance the share repurchase program, Anadarko has sold put options to
independent third parties. These put options entitle the holder to sell shares
of Anadarko common stock to the Company on certain dates at specified prices.
During 2001, Anadarko sold put options for the purchase of a total of 5 million
shares of Anadarko common stock with a notional amount of $240 million. Put
options for 1 million shares were exercised, and put options for 2 million
shares expired unexercised in 2001. During 2001, premiums of $15 million were
received related to these put options and recorded as an increase to paid-in
capital. In January 2002, the Company entered into additional put options for 1
million shares of Anadarko common stock with a notional amount of $46 million
and received a $3 million premium. Put options for an additional 1 million
shares expired unexercised in 2002. The remaining put options for 2 million
shares will expire in March and July 2002, if not exercised. The put options
permit a net-share settlement at the Company's option and do not result in a
liability on the consolidated balance sheet as of December 31, 2001.
As of December 31, 2001 and 2000, the Company had 2 million shares of
common stock in the Anadarko Petroleum Corporation Executives and Directors
Benefits Trust (Trust) to secure present and future unfunded benefit obligations
of the Company. These benefit obligations are provided for under pension plans
and deferred compensation plans for certain employees and non-employee directors
of the Company. The obligations included in Other Long-term Liabilities - Other
are $52 million and $25 million as of December 31, 2001 and 2000, respectively.
The shares issued to the Trust are not considered outstanding for quorum or
voting calculations, but the Trust receives dividends. Under the treasury stock
method, the shares are not included in the calculation of EPS. The fair market
value of these shares is included in common stock and paid-in capital and as a
reduction to stockholders' equity. See Note 16.
Key employees may be granted options to purchase shares of Anadarko common
stock and other stock related awards under the 1993 and the 1999 Stock Incentive
Plans. Stock options are granted at the fair market value of Anadarko stock on
the date of grant and have a maximum term of 11 years from the date of grant.
88
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
8. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
In addition, the Plans provide that shares of common stock may be granted
as restricted stock. Generally, restricted stock is subject to forfeiture
restrictions and cannot be sold, transferred or disposed of during the
restriction period. The holders of the restricted stock have all the rights of a
stockholder of the Company with respect to such shares, including the right to
vote and receive dividends or other distributions paid with respect to such
shares. During 2001, 2000 and 1999, the Company issued 0.2 million, 1.2 million
and 0.1 million shares, respectively, of restricted stock with a
weighted-average grant date fair value of $61.26, $50.21 and $35.87 per share,
respectively. In 2001, 2000 and 1999, expense related to restricted stock grants
was $14 million, $8 million and $2 million, respectively. In 2001 and 2000, 0.03
million and 0.5 million shares, respectively, of unrestricted common stock with
a weighted-average grant date fair value of $65.71 and $48.53 per share,
respectively, were issued related to the RME merger transaction. Merger expenses
in 2001 and 2000 of $2 million and $25 million, respectively, were recognized
related to these shares. Also due to the RME merger transaction, 0.2 million
shares of unrestricted common stock with a weighted-average grant date fair
value of $48.53 per share were issued in 2000. A purchase price adjustment of
$10 million was recorded related to these shares. See Note 2.
Non-employee directors may be granted non-qualified stock options or
deferred stock under the 1998 Director Stock Plan. Stock options are granted at
the fair market value of Anadarko stock on the date of grant and have a maximum
term of ten years from the date of grant. The plan was modified in 2002 to
include deferred stock grants.
Unexercised stock options are included in the diluted EPS using the
treasury stock method. Information regarding the Company's stock option plans is
summarized below:
<Table>
<Caption>
2001 2000 1999
------------------ ------------------ ------------------
WEIGHTED- Weighted- Weighted-
AVERAGE Average Average
EXERCISE Exercise Exercise
SHARES PRICE SHARES PRICE SHARES PRICE
options in millions ------ --------- ------ --------- ------ ---------
SHARES UNDER OPTION AT BEGINNING OF
YEAR 14.4 $41.28 8.9 $29.94 8.5 $29.16
Granted 1.0 $58.12 7.4 $48.80 1.1 $30.39
RME options assumed at merger date -- $ -- 4.4 $38.93 -- $ --
Exercised (0.6) $32.93 (6.3) $32.32 (0.7) $21.05
Surrendered or expired (0.2) $59.72 -- $40.26 -- $35.74
---- ---- ----
SHARES UNDER OPTION AT END OF YEAR 14.6 $42.49 14.4 $41.28 8.9 $29.94
---- ---- ----
Options exercisable at December 31 7.9 $36.26 6.0 $33.91 5.2 $27.78
---- ---- ----
Shares available for future grant at
end of year 3.6 4.8 4.0
---- ---- ----
Weighted-average fair value of
options granted during the year $22.71 $19.09 $11.20
</Table>
89
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
8. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
The following table summarizes information about the Company's stock
options outstanding at December 31, 2001:
<Table>
<Caption>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------- -----------------------
WEIGHTED-
OPTIONS AVERAGE WEIGHTED- OPTIONS WEIGHTED-
RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE
EXERCISE AT YEAR CONTRACTUAL EXERCISE AT YEAR EXERCISE
PRICES END LIFE (YEARS) PRICE END PRICE
-------- ----------- ------------ --------- ----------- ---------
options in millions
$14.91-$30.66 2.7 4.4 $26.75 2.7 $26.75
$31.03-$48.44 3.4 5.3 $35.73 3.3 $35.55
$48.53-$48.53 7.1 5.4 $48.53 1.5 $48.53
$48.97-$71.49 1.4 5.9 $58.62 0.4 $58.78
---- --- ------ --- ------
Total 14.6 5.2 $42.49 7.9 $36.26
---- --- ------ --- ------
</Table>
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions:
<Table>
<Caption>
2001 2000 1999
----- ----- -----
Expected option life - years 4.14 4.35 4.58
Risk-free interest rate 4.48% 6.10% 5.51%
Dividend yield 0.46% 0.50% 0.56%
Volatility 43.79% 39.17% 35.82%
</Table>
SFAS No. 123, "Accounting for Stock-based Compensation," defines a fair
value method of accounting for an employee stock option or similar equity
instrument. SFAS No. 123 allows an entity to continue to measure compensation
costs for these plans using Accounting Principles Board (APB) Opinion No. 25 and
related interpretations. Anadarko has elected to continue using APB No. 25 for
accounting for employee stock compensation plans. Accordingly, no compensation
expense is recognized for stock options granted with an exercise price equal to
the market value of Anadarko stock on the date of grant. If compensation expense
for the Company's stock option plans had been determined using the fair-value
method in SFAS No. 123, the Company's net income and EPS would have been as
shown in the pro forma amounts below:
<Table>
<Caption>
2001 2000 1999
millions except per share amounts ------ ----- ------
Net income (loss) available to common stockholders
before cumulative effect of change in accounting
principle As reported $ (183) $ 813 $ 32
Pro forma $ (225) $ 776 $ 21
Basic EPS As reported $(0.73) $4.42 $ 0.25
Pro forma $(0.90) $4.22 $ 0.17
Diluted EPS As reported $(0.73) $4.25 $ 0.25
Pro forma $(0.90) $4.05 $ 0.17
</Table>
90
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
8. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
The reconciliation between basic and diluted EPS is as follows:
<Table>
<Caption>
FOR THE YEAR ENDED For the Year Ended For the Year Ended
DECEMBER 31, 2001 December 31, 2000 December 31, 1999
-------------------------- --------------------------- ---------------------------
PER SHARE Per Share Per Share
LOSS SHARES AMOUNT INCOME SHARES AMOUNT INCOME SHARES AMOUNT
millions except per share amounts ----- ------ --------- ------ ------ --------- ------ ------ ---------
BASIC EPS
Net income (loss) available to common
stockholders before change in
accounting principle $(183) 250 $(0.73) $813 184 $4.42 $32 125 $0.25
------ ----- -----
Effect of convertible debentures and
ZYP-CODES -- -- 6 7 -- --
Effect of dilutive stock options and
performance-based stock awards -- -- -- 2 -- 1
----- --- ---- --- --- ---
DILUTED EPS
Net income (loss) available to common
stockholders plus assumed conversion $(183) 250 $(0.73) $819 193 $4.25 $32 126 $0.25
----- --- ------ ---- --- ----- --- --- -----
</Table>
For the years ended December 31, 2001, 2000 and 1999, options for 1.2
million, 0.1 million and 4.4 million shares of common stock, respectively, were
excluded from the diluted EPS calculation because the options' exercise price
was greater than the average market price of common stock for the periods. For
the year ended December 31, 2001, put options for 2 million shares of common
stock were excluded because the put options' exercise price was less than the
average market price of common stock for the period. For the year ended December
31, 2001, there were 15.9 million potential common shares related to outstanding
stock options, convertible debentures and ZYP-CODES that were excluded from the
computation of diluted EPS because they had an anti-dilutive effect.
9. STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION
The amounts of cash paid (received) for interest (net of amounts
capitalized) and income taxes are as follows:
<Table>
<Caption>
2001 2000 1999
millions ---- ---- ----
Interest $ 96 $90 $70
Income taxes paid (received) $169 $40 $(1)
</Table>
The RME merger transaction was completed through the issuance of common
stock, which was a non-cash transaction that was not reflected in the statement
of cash flows. See Note 2. The $53 million of acquisition costs for 2000
reflected in Cash Flow from Investing Activities in the consolidated statement
of cash flows represents capitalized merger costs in connection with the RME
merger of $147 million, less the cash acquired on the date of the RME merger of
$94 million.
10. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS
Anadarko has a Production Sharing Agreement (PSA) with SONATRACH, the
national oil and gas enterprise of Algeria. SONATRACH has owned the Company's
common stock since 1986 and at year-end 2001 was the beneficial owner of 5% of
Anadarko's outstanding common stock. The PSA gives Anadarko the right to develop
and produce liquid hydrocarbons in Algeria, subject to the sharing of production
with SONATRACH. Anadarko has two partners in the PSA. Approximately $10 million,
$10 million and $15 million was paid to SONATRACH in 2001, 2000 and 1999,
respectively, for charges related to oil
91
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
10. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS (CONTINUED)
purchases, transportation of oil, well testing services, reservoir studies,
laboratory services and equipment usage. During 2001, 2000 and 1999, $7 million,
$6 million and $21 million, respectively, was received and $7 million was
included in accounts payable and $12 million was included in accounts receivable
as of December 31, 2001 and 2000, respectively, from SONATRACH for joint
interest billings of development costs in Algeria under the PSA. During 2000,
Anadarko and SONATRACH formed an Algeria non-profit company, Groupement Berkine,
to carry out their joint operating activities under the PSA. SONATRACH and
Anadarko fund the expenditures incurred by Groupement Berkine according to their
participating interests under the PSA.
In 2001, Anadarko and its partners signed an amendment to the PSA with
SONATRACH, which allows exploration to resume on Blocks 404, 208 and 211 in
areas outside of the exploitation license boundaries encompassing the previous
discoveries. Under the terms of the new three-phase exploration program,
Anadarko and its partners will spend a minimum of $55 million and expect to
drill exploration wells beginning in 2002.
Anadarko also signed an exploration license with SONATRACH for Block 406b
at Algeria's licensing round in 2001, in which the Company has a 100% interest.
The license has a three-year initial term. A work program commitment includes
seismic acquisition and one exploration well.
Anadarko and partners have two Engineering, Procurement and Construction
(EPC) contracts to build oil production facilities in Algeria with Brown &
Root-Condor, a company jointly owned by Brown & Root and affiliates of
SONATRACH. For the years ended December 31, 2000 and 1999, approximately $4
million and $43 million, respectively, was paid to Brown & Root-Condor under the
EPC contracts. No amounts were paid to Brown & Root-Condor under the EPC
contracts in 2001.
Political unrest continues in Algeria. Anadarko is closely monitoring the
situation and has taken reasonable and prudent steps to ensure the safety of
employees and the security of its facilities in the remote regions of the Sahara
Desert. Anadarko is presently unable to predict with certainty any effect the
current situation may have on activity planned for 2002 and beyond. However, the
situation has not had any material effect on the Company's operations to date.
The Company's activities in Algeria also are subject to the general risks
associated with all foreign operations.
Anadarko recognized revenues of $12 million in 2001 for cumulative
preferred dividends declared by OCI Wyoming Co., an equity affiliate. Anadarko
owns a 20% common stock interest in OCI Wyoming Co. along with 100% of the
cumulative preferred stock. The amount recorded to income in 2001 was for
dividends in arrears for the period 1999 through 2001.
The Company's natural gas is sold to interstate and intrastate gas
pipelines, direct end-users, industrial users, local distribution companies and
gas marketers. Crude oil and condensate are sold to marketers, gatherers and
refiners. NGLs are sold to direct end-users, refiners and marketers. These
purchasers are located in the United States, Canada, England, Mexico, Italy and
Switzerland. The majority of the Company's receivables are paid within two
months following the month of purchase.
The Company generally performs a credit analysis of customers prior to
making any sales to new customers or increasing credit for existing customers.
Based upon this credit analysis, the Company may require a standby letter of
credit or a financial guarantee. As of December 31, 2001 and 2000, accounts
receivable are shown net of allowance for doubtful accounts of $44 million and
$39 million, respectively.
In 2001, sales to Duke Energy and affiliates (Duke Energy) were $1.45
billion, which accounted for 17% of the Company's total 2001 revenues. In 2000,
sales to Duke Energy were $1.01 billion, which accounted for 18% of the
Company's total 2000 revenues. In 1999, sales to CoEnergy Trading Co. were $181
million, which accounted for 11% of the Company's total 1999 revenues.
92
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
11. SEGMENT AND GEOGRAPHIC INFORMATION
Anadarko's primary business segments are vertically integrated business
units that are principally within the oil and gas industry. These segments are
managed separately because of their unique technology, marketing and
distribution requirements. The Company's three segments are upstream oil and gas
activities, downstream marketing activities and minerals activities. The oil and
gas exploration and production segment finds and produces natural gas, crude
oil, condensate and NGLs. The marketing segment is responsible for selling most
of Anadarko's natural gas production as well as volumes of gas, oil and NGLs
purchased from third parties. The minerals segment finds and produces minerals
in several coal, trona (natural soda ash) and industrial mineral mines. The
segment shown as All Other includes other smaller operating units, corporate
activities, financing activities and intercompany eliminations.
The Company's accounting policies for segments are the same as those
described in the summary of accounting policies. Management evaluates segment
performance based on profit or loss from operations before income taxes and
various other factors. Transfers between segments are accounted for at market
value.
The following table illustrates information related to Anadarko's business
segments:
<Table>
<Caption>
OIL AND GAS
EXPLORATION ALL
AND PRODUCTION MARKETING MINERALS OTHER TOTAL
millions -------------- --------- -------- ------- -------
2001
Revenues $ 3,048 $5,256 $ 57 $ 8 $ 8,369
Intersegment revenues 1,480 17 -- (1,497) --
------- ------ ------ ------- -------
Total revenues 4,528 5,273 57 (1,489) 8,369
Depreciation, depletion and
amortization 1,110 12 4 28 1,154
Impairments related to oil and gas
properties 2,546 -- -- -- 2,546
Other costs and expenses 950 5,246 4 (1,213) 4,987
------- ------ ------ ------- -------
Total costs and expenses 4,606 5,258 8 (1,185) 8,687
Other (income) expense -- (91) -- 163 72
------- ------ ------ ------- -------
Income (loss) before income taxes $ (78) $ 106 $ 49 $ (467) $ (390)
------- ------ ------ ------- -------
Net properties and equipment $11,765 $ 253 $1,206 $ 413 $13,637
------- ------ ------ ------- -------
Capital expenditures $ 3,072 $ 66 $ -- $ 178 $ 3,316
------- ------ ------ ------- -------
</Table>
<Table>
2000
Revenues $ 1,869 $3,571 $ 52 $ 8 $ 5,500
Intersegment revenues 934 164 -- (1,098) --
------- ------ ------ ------- -------
Total revenues 2,803 3,735 52 (1,090) 5,500
Depreciation, depletion and
amortization 570 8 2 13 593
Impairments related to oil and gas
properties 50 -- -- -- 50
Other costs and expenses 575 3,791 2 (930) 3,438
------- ------ ------ ------- -------
Total costs and expenses 1,195 3,799 4 (917) 4,081
Other (income) expense -- (174) -- 167 (7)
------- ------ ------ ------- -------
Income (loss) before income taxes $ 1,608 $ 110 $ 48 $ (340) $ 1,426
------- ------ ------ ------- -------
Net properties and equipment $11,330 $ 166 $1,211 $ 304 $13,011
------- ------ ------ ------- -------
Capital expenditures $ 1,630 $ 41 $ -- $ 37 $ 1,708
</Table>
93
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
11. SEGMENT AND GEOGRAPHIC INFORMATION (CONTINUED)
<Table>
<Caption>
OIL AND GAS
EXPLORATION ALL
AND PRODUCTION MARKETING MINERALS OTHER TOTAL
millions -------------- --------- -------- ------- -------
------- ------ ------ ------- -------
1999
Revenues $ 309 $1,395 $ -- $ 2 $ 1,706
Intersegment revenues 379 37 -- (416) --
------- ------ ------ ------- -------
Total revenues 688 1,432 -- (414) 1,706
Depreciation, depletion and
amortization 196 7 -- 15 218
Impairments related to oil and gas
properties 24 -- -- -- 24
Other costs and expenses 196 1,421 -- (328) 1,289
------- ------ ------ ------- -------
Total costs and expenses 416 1,428 -- (313) 1,531
Other (income) expense -- -- -- 70 70
------- ------ ------ ------- -------
Income (loss) before income taxes $ 272 $ 4 $ -- $ (171) $ 105
------- ------ ------ ------- -------
Net properties and equipment $ 3,490 $ 132 $ -- $ 59 $ 3,681
------- ------ ------ ------- -------
Capital expenditures $ 653 $ 20 $ -- $ 7 $ 680
------- ------ ------ ------- -------
</Table>
The following table shows Anadarko's revenues (based on the origin of the
sales) and net properties and equipment by geographic area:
<Table>
<Caption>
2001 2000 1999
millions ------ ------ ------
REVENUES
United States $6,647 $4,649 $1,592
Canada 1,336 447 --
Algeria 195 271 114
Other International 191 133 --
------ ------ ------
Total $8,369 $5,500 $1,706
------ ------ ------
</Table>
<Table>
<Caption>
2001 2000
millions ------- -------
NET PROPERTIES AND EQUIPMENT
United States $10,072 $10,131
Canada 2,010 1,540
Algeria 807 653
Other International 748 687
------- -------
Total $13,637 $13,011
------- -------
</Table>
12. OTHER TAXES
Significant taxes other than income taxes are as follows:
<Table>
<Caption>
2001 2000 1999
millions ---- ---- ----
Production and severance $139 $ 88 $17
Ad valorem 85 28 14
Payroll and other 23 12 5
---- ---- ---
Total $247 $128 $36
---- ---- ---
</Table>
94
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
13. OTHER (INCOME) EXPENSE
Other (income) expense consists of the following:
<Table>
<Caption>
2001 2000 1999
millions ---- ----- ----
Firm transportation keep-whole contract valuation (See Note
6) $(91) $(175) $--
Foreign currency exchange 29 7 --
Change in time value options (18) -- --
Other 15 1 (4)
---- ----- ---
Total $(65) $(167) $(4)
---- ----- ---
</Table>
14. INCOME TAXES
Income tax expense, including deferred amounts, is summarized as follows:
<Table>
<Caption>
2001 2000 1999
millions ----- ---- ----
CURRENT
Federal $ 32 $ 8 $ 1
State 5 3 --
Foreign 50 67 1
----- ---- ---
Total 87 78 2
----- ---- ---
DEFERRED
Federal (38) 405 25
State (5) 24 2
Foreign (258) 95 33
----- ---- ---
Total (301) 524 60
----- ---- ---
Total $(214) $602 $62
----- ---- ---
</Table>
Total income taxes were different than the amounts computed by applying the
statutory income tax rate to income (loss) before income taxes. The sources of
these differences are as follows:
<Table>
<Caption>
2001 2000 1999
millions ----- ------ ----
Income (Loss) Before Income Taxes
Domestic $ 67 $1,085 $ 46
Foreign (457) 341 59
----- ------ ----
Total $(390) $1,426 $105
----- ------ ----
Statutory tax rate 35% 35% 35%
Tax computed at statutory rate $(137) $ 499 $ 37
Adjustments resulting from:
State income taxes (net of federal income tax benefit) -- 17 1
Oil and gas credits (22) (13) (1)
Taxes related to foreign activities (net of federal income
tax benefit) (51) 134 22
Reversal of goodwill amortization 22 11 --
Effect of change in Canadian income tax rate (31) -- --
Other -- net 5 (46) 3
----- ------ ----
Total income taxes $(214) $ 602 $ 62
----- ------ ----
Effective tax rate 55% 42% 59%
----- ------ ----
</Table>
95
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
14. INCOME TAXES (CONTINUED)
The tax benefit of compensation expense for tax purposes in excess of
amounts recognized for financial accounting purposes has been credited directly
to stockholders' equity. For 2001, 2000 and 1999, the tax benefit amounted to $6
million, $67 million and $4 million, respectively.
A net tax benefit of $42 million resulting from the Company's restructuring
of certain foreign operations in 2000 was recorded to a deferred liability
account. An additional net tax benefit of $49 million was recorded to the
account during 2001. In addition, a net tax benefit previously recorded to the
account in the amount of $152 million was reversed to goodwill in 2001 as a
result of the sale of a wholly-owned subsidiary, which was acquired in the RME
merger. The resulting balance after considering amortization, a deferred asset,
is reflected in the Company's other long-term assets.
Tax expense in the amount of $10 million was recorded directly to goodwill
relating to the sale in 2001 of a wholly-owned subsidiary, which was acquired in
the RME merger.
The tax effects of temporary differences that give rise to significant
portions of the deferred tax liabilities (assets) at December 31, 2001 and 2000
are as follows:
<Table>
<Caption>
2001 2000
millions ------ ------
Oil and gas exploration and development costs $2,797 $3,090
Mineral operations 422 424
Other 506 392
------ ------
Gross noncurrent deferred tax liabilities 3,725 3,906
------ ------
Net operating loss carryforward -- (55)
Alternative minimum tax credit carryforward (136) (68)
Other (169) (150)
------ ------
Gross noncurrent deferred tax assets (305) (273)
Less valuation allowance 31 --
------ ------
Net noncurrent deferred tax assets (274) (273)
Net noncurrent deferred tax liabilities $3,451 $3,633
------ ------
Alternative minimum tax credit carryforward $ -- $ (65)
------ ------
Gross current deferred tax asset $ -- $ (65)
------ ------
</Table>
The net increase in the valuation allowance during 2001 was $31 million. Of
this amount, $14 million was recorded to a deferred asset account. Subsequently
recognized tax benefits relating to the reversal of the $14 million will be
recorded to a deferred asset account.
Tax credit carryforwards at December 31, 2001, which are available for
future utilization on federal income tax returns, are as follows:
<Table>
<Caption>
AMOUNT EXPIRATION
millions ------ ----------
Alternative minimum tax credit $136 Unlimited
General business tax credit $ 32 2006-2021
</Table>
96
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
15. LEASE COMMITMENTS
The Company has various commitments under non-cancelable operating lease
agreements for buildings, facilities and equipment, the majority of which expire
at various dates through 2016. The Company also maintains a capital lease for
certain furniture and office walls, which were sold but the liability was
retained. The majority of the operating leases are expected to be renewed or
replaced as they expire. At December 31, 2001, future minimum lease payments and
receipts due under operating and capital leases are as follows:
<Table>
<Caption>
OPERATING
CAPITAL OPERATING SUBLEASE
LEASES LEASES INCOME
millions ------- --------- ---------
2002 $ 3 $ 72 $ (30)
2003 3 69 (29)
2004 6 66 (6)
2005 1 54 (5)
2006 -- 51 (5)
Later years -- 263 (25)
--- ---- -----
Total future minimum lease payments 13 $575 $(100)
---- -----
Less: amounts representing interest (1)
---
Present value of minimum capital lease obligations 12
---
Less: short-term portion of capital lease obligations (3)
---
Long-term portion of capital lease obligations $ 9
---
</Table>
Total rental expense, net of sublease income, amounted to $43 million, $48
million and $33 million in 2001, 2000 and 1999, respectively. Capital leases
included in fixed assets were zero and $15 million at December 31, 2001 and
2000, respectively.
As a result of the RME merger, the Company recorded a provision for certain
operating lease obligations in excess of expected sublease income. The provision
for these operating lease obligations was $24 million as of December 31, 2000.
In 2001, the Company entered into an agreement under which a third party assumed
the Company's full liability under certain RME lease agreements. Therefore,
these RME lease agreements are not included in the operating lease obligations
shown above.
SYNTHETIC LEASES In November 1999, Anadarko entered into a build-to-suit lease
arrangement for its corporate office building in The Woodlands, Texas. The
development and acquisition of the property was financed by a special purpose
entity (SPE) sponsored by a financial institution. The lease balance to be
funded under this arrangement will not exceed $185 million. The SPE is not
consolidated in the Company's financial statements and, based on the initial
terms of the agreement, the Company has accounted for this arrangement as an
operating lease in accordance with SFAS No. 13, "Accounting for Leases."
The initial lease term is five years, with up to seven one-year renewal
options. Monthly lease payments are based on the London interbank borrowing rate
applied against the lease balance and are expected to begin in 2002. Future
minimum lease payments under this lease are included in the table above. The
lease contains various covenants including covenants regarding the Company's
financial condition. Default under the lease, including violation of these
covenants, could require the Company to purchase the facility for a specified
amount, which approximates the lessor's original cost ($123 million funded as of
December 31, 2001). As of December 31, 2001, the Company was in compliance with
these covenants.
At the end of the lease term, the Company has an option to either purchase
the facility for the purchase option amount of the lease balance plus any
outstanding lease payments or to assist the SPE in the sale of the property. The
Company has provided a residual value guarantee for any deficiency if the
property is sold for
97
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
15. LEASE COMMITMENTS (CONTINUED)
less than the sale option amount ($104 million at December 31, 2001). In
addition, the Company is entitled to any proceeds from a sale of the property in
excess of the purchase option amount.
In December 2000, the Company entered into a lease arrangement for an
office building in The Woodlands, Texas. The acquisition of the property was
financed by an SPE sponsored by a financial institution. The amount funded was
$48 million. The SPE is not consolidated in the Company's financial statements
and the Company has accounted for this arrangement as an operating lease in
accordance with SFAS No. 13.
The initial lease term is five years. Monthly lease payments, which began
in 2001, are based on the London interbank borrowing rate applied against the
$48 million lease balance. Future minimum lease payments under this lease are
included in the table above. The lease contains various covenants including
covenants regarding the Company's financial condition. Default under the lease,
including violation of these covenants, could require the Company to purchase
the facility for a specified amount, which approximates the lessor's original
cost ($48 million). As of December 31, 2001, the Company is in compliance with
these covenants.
At the end of the lease term, the Company has an option to either purchase
the facility for the purchase option amount of $48 million plus any outstanding
lease payments or to assist the SPE in the sale of the property. The Company has
provided a residual value guarantee for any deficiency if the property is sold
for less than the sale option amount ($39 million at December 31, 2001). In
addition, the Company is entitled to any proceeds from a sale of the property in
excess of the purchase option amount.
If for either of these leases, the Company determines that it is probable
that the expected fair value of the property at the end of the lease term will
be less than the purchase option amount, the Company will accrue the expected
loss on a straight line basis over the remaining lease term. Currently,
management does not believe it is probable that the fair market value of either
of these properties will be less than the purchase option amount at the end of
the lease term.
In December 2001, the Company signed a letter of intent under which a
floating production platform for its Marco Polo discovery in Green Canyon Block
608 of the Gulf of Mexico will be installed. The other partners will construct
the platform and processing facilities that upon completion, expected in 2004,
will be operated by Anadarko. The proposed agreement provides that Anadarko will
dedicate its production from Green Canyon Block 608 and 11 other Green Canyon
blocks to the processing facilities. The proposed agreement will require a
monthly demand charge of slightly over $2 million for five years beginning at
the time of project completion and a processing fee based upon production.
Anadarko will be entitled to 25% of the net after tax cash proceeds from these
facilities after payout, as defined, is attained. The letter of intent does not
contain any purchase options, purchase obligations or value guarantees. The
table of future minimum lease payments above does not include any amounts
related to this letter of intent.
16. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS The Company has a defined
benefit pension plan and supplemental plans which are non-contributory pension
plans. The plans of RME were merged with Anadarko's plans in December 2000. The
Company also provides certain health care and life insurance benefits for
retired employees. Health care benefits are funded by contributions from the
Company and the retiree, with the retiree contributions adjusted to match the
provisions of the Company's health care plans. The Company's retiree life
insurance plan is non-contributory.
98
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
16. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
(CONTINUED)
The following table sets forth the Company's pension and other
postretirement benefits changes in benefit obligation, fair value of plan
assets, funded status and amounts recognized in the financial statements as of
December 31, 2001 and 2000.
<Table>
<Caption>
PENSION BENEFITS OTHER BENEFITS
----------------- --------------
2001 2000 2001 2000
millions ----- ----- ----- ----
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $377 $ 80 $ 75 $ 35
Service cost 11 8 3 2
Interest cost 27 15 5 4
Plan merger -- 277 -- 39
Plan amendments 10 -- 20 (5)
Actuarial (gain) loss 18 12 25 2
Foreign currency exchange rate change (2) -- -- --
Benefit payments and settlements (24) (15) (5) (2)
---- ---- ----- ----
Benefit obligation at end of year $417 $377 $ 123 $ 75
---- ---- ----- ----
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $396 $ 62 $ -- $ --
Actual return on plan assets (32) 20 -- --
Plan merger -- 329 -- --
Employer contributions 1 1 5 2
Foreign currency exchange rate change (3) -- -- --
Benefit payments (24) (16) (5) (2)
---- ---- ----- ----
Fair value of plan assets at end of year $338 $396 $ -- $ --
---- ---- ----- ----
Funded status of the plan $(79) $ 19 $(123) $(75)
Unrecognized actuarial (gain) loss 80 3 23 (2)
Unrecognized prior service cost 8 (2) 16 (4)
Unrecognized initial asset (2) (3) -- --
---- ---- ----- ----
Total recognized $ 7 $ 17 $ (84) $(81)
---- ---- ----- ----
TOTAL RECOGNIZED AMOUNTS IN THE BALANCE SHEET CONSIST
OF:
Prepaid benefit cost $ 23 $ 24 $ -- $ --
Accrued benefit liability (51) (11) (84) (81)
Intangible asset 31 4 -- --
Other comprehensive expense 4 -- -- --
---- ---- ----- ----
Total recognized $ 7 $ 17 $ (84) $(81)
---- ---- ----- ----
</Table>
Following are the weighted-average assumptions used by the Company in
determining the accumulated pension and postretirement benefit obligations as of
December 31, 2001 and 2000:
<Table>
<Caption>
PENSION BENEFITS OTHER BENEFITS
-------------------- ---------------
2001 2000 2001 2000
percent ---- ----------- ----- -----
Discount rate 7.25% 7.5% 7.25% 7.5%
Long-term rate of return on plan assets 9.0% 7.5% to 8.0% N/A n/a
Rates of increase in compensation levels 5.0% 5.0% to 5.5% 5.0% 5.0%
</Table>
99
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
16. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
(CONTINUED)
For measurement purposes, a 10% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2001. The rate was assumed
to decrease gradually to 5% in 2006 and later years.
<Table>
<Caption>
PENSION BENEFITS OTHER BENEFITS
------------------ ------------------
2001 2000 1999 2001 2000 1999
millions ---- ---- ---- ---- ---- ----
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 11 $ 8 $ 7 $ 3 $ 2 $ 2
Interest cost 27 15 6 6 4 3
Expected return on plan assets (28) (13) (5) -- -- --
Amortization values and deferrals 1 -- -- (1) (1) --
---- ---- --- --- --- ---
Net periodic benefit cost $ 11 $ 10 $ 8 $ 8 $ 5 $ 5
---- ---- --- --- --- ---
</Table>
The projected benefit obligation, accumulated benefit obligation and fair
value of plan assets for the pension plan with accumulated benefit obligations
in excess of plan assets were $393 million, $344 million and $297 million,
respectively, as of December 31, 2001, and $32 million, $29 million and $0,
respectively, as of December 31, 2000. The Company's benefit obligation under
the unfunded pension plans are secured by the Anadarko Petroleum Corporation
Executives and Directors Benefits Trust. See Note 8.
The assumed health care cost trend rate has a significant effect on the
amounts reported for the health care plan. A 1% change in the assumed health
care cost trend rate would have the following effects:
<Table>
<Caption>
1% INCREASE 1% DECREASE
millions ----------- -----------
Effect on total of service and interest cost components $ 2 $ (2)
Effect on postretirement benefit obligation $16 $(14)
</Table>
EMPLOYEE SAVINGS PLAN The Company has an employee savings plan (ESP), which is
a defined contribution plan. The Company matches a portion of employees'
contributions with shares of the Company's common stock. Participation in the
ESP is voluntary and all regular employees of the Company are eligible to
participate. The Company charged to expense plan contributions of $11 million,
$7 million and $5 million during 2001, 2000 and 1999, respectively. The 2001
contributions were funded through the Employee Stock Ownership Plan (ESOP).
EMPLOYEE STOCK OWNERSHIP PLAN Effective July 14, 2000, Anadarko adopted the RME
ESOP and the shares in the ESOP were converted to shares of Anadarko common
stock. As of July 14, 2000, the ESOP consisted of 1.2 million shares or $74
million of common stock (the ESOP shares) to be used to fund the Company's
matching obligation under the RME Thrift Plan. All domestic regular employees of
RME were eligible to participate in the ESOP. Effective December 31, 2000, the
ESOP was merged into the RME Thrift Plan, which was merged into the Anadarko
ESP. Beginning January 2001, the Company began using unallocated ESOP shares for
Company matching under the Anadarko ESP.
The ESOP shares, which are held in trust, were originally purchased with
the proceeds from a 30-year loan from RME in 1997. These shares were pledged as
collateral for the loan. As loan payments are made, shares are released from
collateral, based on the proportion of debt service paid. Scheduled principal
and interest requirements are funded with dividends paid on the ESOP shares and
with cash contributions from the Company. Principal or interest prepayments may
be made to ensure that the Company's minimum matching obligation is met.
Shares held by the ESOP are included in the computation of earnings per
share as ESOP shares are released from collateral. Releases of ESOP shares will
be allocated to participants' accounts and will be charged to compensation
expense at the fair market value of the shares on the date of the employer
match.
100
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
16. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
(CONTINUED)
As of December 31, 2001 and 2000, the unallocated shares in the ESOP were
0.9 million and 1.1 million, respectively, and the fair value of unallocated
ESOP shares at December 31, 2001 and 2000 was $52 million and $79 million,
respectively. In 2000, compensation cost related to the allocation of ESOP
shares to participants' accounts, other than expense under the ESP plan, was $2
million. In 2001, no compensation cost related to the allocation of ESOP shares,
other than expense under the ESP, was recorded.
17. CONTINGENCIES
GENERAL The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third-party contractors
alleging exposure to asbestos and benzene while working at a refinery in Corpus
Christi, Texas, which RME sold in segments in 1987 and 1989. While the ultimate
outcome and impact on the Company cannot be predicted with certainty, management
believes that the resolution of these proceedings will not have a material
adverse effect on the consolidated financial position of the Company, although
results of operations and cash flow could be significantly impacted in the
reporting periods in which such matters are resolved. Discussed below are
several specific proceedings.
SUPERFUND Presently, six Superfund sites (five federal and one state) are
included in the Superfund Reserve.
OPERATING INDUSTRIES, INC. (FEDERAL) -- The former municipal industrial
landfill, located in Monterey Park, California, was operational between
1948 and 1984. RME was noticed as a Potentially Responsible Party (PRP) in
June 1986 for its Wilmington Production Field's and Wilmington Refinery's
contributions. The Company has agreed to participate in a settlement with
the Environmental Protection Agency (EPA). The Company's estimated share of
this settlement is $4.3 million. The settlement and consent decree are
undergoing final agency review.
EKOTEK (FEDERAL) -- The facility in Salt Lake City, Utah operated as a
refinery from 1953 until 1978, at which time it was converted to a
hazardous waste storage/treatment and petroleum recycling facility. The
Utah Department of Environmental Quality issued multiple Notices of
Violation to the facility in 1988, resulting in the facility's closing.
Bear Creek Uranium Company, an affiliate, was named as a PRP for its
contributions of used/waste oils. Remediation of the Ekotek site is nearing
completion and no additional funding requests are expected.
CASMALIA (FEDERAL) -- The Casmalia facility, located in Santa Barbara
County, California, is a former Resource Conservation and Recovery Act
hazardous waste disposal site. RME was noticed as a PRP in March 1993.
RME's waste contribution is attributed to the Wilmington Refinery.
Negotiations with the EPA are ongoing. The Company believes its share of
the costs will be about $0.1 million.
GEOTHERMAL INC. (STATE) -- The site, located in Middletown, California, was
permitted as a Class II surface impoundment facility for geothermal wastes.
Sludge from drilling operations and power plant wastes generated at the
Geysers Geothermal Field between 1976 and 1987 were transported to the
facility for treatment/disposal. The waste material was placed in
evaporation ponds and allowed to dry. The resultant solids were buried
onsite. Site remediation began in 1984. Anadarko was noticed as a PRP in
December 1993. Several remedial methods are currently being evaluated to
determine the most effective for addressing site groundwater impacts. The
Company believes its share of the costs will be about $0.1 million.
PCB TREATMENT, INC. (FEDERAL) -- The PCB treatment/disposal site, located
in Kansas City, Kansas and Kansas City, Missouri, operated from 1982 until
1986 when regulatory violations forced its closure. RME was noticed as a
PRP in October 1998 for contributions attributed to Wilmington Refinery
operations.
101
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
17. CONTINGENCIES (CONTINUED)
PCB impacts are currently limited to the facility structures and
surrounding soils. Remedial alternatives are under review. The Company
believes its share of the costs will be about $0.1 million.
SUMMITVILLE MINE (FEDERAL) -- RME and Cleveland Cliffs Iron Company
conducted exploration activities at the site in Summitville, Colorado
between 1967 and 1969. The exploration efforts ceased after the companies
determined operations were not commercially viable. Several other companies
initiated various exploration efforts at the site until 1984 when Galactic
Resources permitted a heap leach gold mine at the site. Galactic filed for
bankruptcy in 1992 and the EPA implemented a cleanup response in 1993. RME
and Cleveland Cliffs negotiated a settlement with the EPA regarding federal
liability at the site that excluded claims for natural resource damages.
Recently, RME and Cleveland Cliffs reached a settlement with the State of
Colorado regarding state liability at the site that includes natural
resource damages. This agreement calls for the payment of $0.8 million
(RME's share $0.4 million). This agreement became final upon entry of the
Settlement Agreement and Consent Decree by the United States District Court
for the District of Colorado on September 30, 2001. RME fulfilled its
obligations in October 2001 by payment of $0.4 million to the State of
Colorado.
ROYALTY LITIGATION During September 2000, the Company was named as a defendant
in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et
al. (the "Gas Qui Tam case") filed in the U.S. District Court for the Eastern
District of Texas, Lufkin Division. This lawsuit generally alleges that the
Company and 118 other defendants improperly measured and otherwise undervalued
natural gas in connection with a payment of royalties on production from federal
and Indian lands. The case has been transferred to the U.S. District Court,
Multi-District Litigation Docket pending in Wyoming. Based on the Company's
present understanding of the various governmental and False Claims Act
proceedings described above, the Company believes that it has substantial
defenses to these claims and intends to vigorously assert such defenses.
However, if the Company is found to have violated the Civil False Claims Act,
the Company could be subject to a variety of sanctions, including treble damages
and substantial monetary fines.
A group of royalty owners purporting to represent RME's gas royalty owners
in Texas (Neinast, et al.) was granted class action certification in December
1999, by the 21st Judicial District Court of Washington County, Texas, in
connection with a gas royalty underpayment case against the Company. This
certification did not constitute a review by the Court of the merits of the
claims being asserted. The royalty owners' pleadings did not specify the damages
being claimed, although most recently a demand for damages in the amount of $100
million has been asserted. The Company is of the opinion that the amount of
damages at risk is substantially less than the amount demanded by the class
action counsel and the Company intends to vigorously assert its defenses. The
Company appealed the class certification order. A favorable decision from the
Houston Court of Appeals decertified the class. It is anticipated that the
royalty owners will now appeal this matter to the Texas Supreme Court.
A class action lawsuit entitled Gilbert H. Coulter, et al. v. Anadarko
Petroleum Corporation has been certified in the 26th Judicial District Court,
Stevens County, Kansas. In this action, the royalty owners contend that royalty
was underpaid as a result of the deduction for certain post-production costs in
the calculation of royalty. The Company believes that its method of calculating
royalty was proper and that its gas was marketable in the condition produced,
and thus plaintiffs' claims are without merit. This case was certified as a
class action in August 2000 and was tried in February 2002. A decision from the
trial court is expected by the end of 2002.
WYOMING TAX LITIGATION RME filed tax appeals in March 1999 before the Wyoming
Board of Equalization, alleging that the Wyoming Department of Revenue's
revaluation of RME's crude oil production and natural gas production for the
years 1989 through 1995 was erroneous. RME also filed a lawsuit in September
2000 in the First District Court of Laramie County, Wyoming, alleging that
Wyoming's valuation statute was impermissibly vague. The Department of Revenue
revalued RME's crude oil production based upon prices in
102
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
17. CONTINGENCIES (CONTINUED)
Cushing, Oklahoma, as opposed to the price RME received at the wellhead from its
marketing affiliate. The Department of Revenue also sought to revalue RME's
natural gas production under a new valuation formula that was approved in a
decision the Board of Equalization issued in other litigation while RME's
dispute remained pending. RME argued that the price it received for its crude
oil production reflected the actual market value of the oil at the wellhead, and
that it was neither appropriate nor lawful to value crude oil in Wyoming
according to transactions at Cushing. RME also argued that the formula the
Department of Revenue previously had used to value natural gas production for
many years was the proper formula, and that the new formula approved by the
Board of Equalization in the third-party litigation was erroneous. The amount in
controversy was approximately $27 million. The Company settled the dispute for
$10 million, of which RME already had paid $7 million under protest prior to the
merger. As a result of the settlement, the parties have agreed to dismiss the
tax appeals and the lawsuit.
CITGO LITIGATION CITGO Petroleum Corporation's (CITGO) claims arise out of an
Asset Purchase and Contribution Agreement dated March 17, 1987 whereby RME's
predecessor sold a refinery located in Corpus Christi, Texas, to CITGO's
predecessor. After the sale of the refinery, numerous individuals living near
the refinery sued CITGO (the Neighborhood Litigation) thereby implicating the
Asset Purchase and Contribution Agreement indemnity provision. CITGO and RME
eventually entered into a settlement agreement to allocate, on an interim basis,
each party's liability for defense and liability cost in that and related
litigation. That agreement provides that once the Neighborhood Litigation and
certain related claims are resolved, then the parties will determine their final
indemnity obligations to each other through binding arbitration. At the present
time, RME and CITGO have agreed to defer arbitrating the allocation of
responsibility for this liability in order to focus their efforts on a global
settlement. Arbitration will resume upon request of either CITGO or RME. In
conjunction with this matter, RME sued Continental Insurance for denial of
coverage for claims related to this dispute. RME and Continental Insurance
settled the insurance coverage litigation which resulted in Continental
Insurance paying RME for the claims. Negotiations and discussions with CITGO
continue.
KANSAS AD VALOREM TAX
General The Natural Gas Policy Act of 1978 allowed a "severance, production or
similar" tax to be included as an add-on, over and above the maximum lawful
price for natural gas. Based on the Federal Energy Regulatory Commission (FERC)
ruling that the Kansas ad valorem tax was such a tax, the Company collected the
Kansas ad valorem tax.
Background of PanEnergy Litigation FERC's ruling regarding the ability of
producers to collect the Kansas ad valorem tax was appealed to the United States
Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The Court
held in June 1988 that FERC failed to provide a reasoned basis for its findings
and remanded the case to FERC.
Ultimately, the D.C. Circuit issued a decision on August 2, 1996 ruling
that producers must refund all Kansas ad valorem taxes collected relating to
production since October 1983. The Company filed a petition for writ of
certiorari with the Supreme Court. That petition was denied on May 12, 1997.
PanEnergy Litigation On May 13, 1997, the Company filed a lawsuit in the
Federal District Court for the Southern District of Texas against PanEnergy
seeking declaration that pursuant to prior agreements Anadarko is not required
to issue refunds to PanEnergy for the principal amount of $14 million (before
taxes) and, if the petition for adjustment is denied in its entirety by FERC
with respect to PanEnergy refunds, interest in an amount of $38 million (before
taxes). The Company also sought from PanEnergy the return of the $1 million
(before taxes) charged against income in 1993 and 1994. In October 2000, the
U.S. Magistrate issued recommendations concerning motions for summary judgment
previously filed by both parties. In essence, the
103
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
17. CONTINGENCIES (CONTINUED)
Magistrate's recommendation finds that the Company should be responsible for
refunds attributable to the time period following August 1, 1985 while Duke
Energy (as the successor company to Anadarko Production Company) should be
responsible for refunds attributable to the time period before August 1, 1985.
The Company has reached a settlement agreement with PanEnergy that requires
the Company to pay $15 million for settlement in full of all matters relating to
the refunds of Kansas ad valorem tax reimbursements collected by the Company as
first seller from August 1, 1985 through 1988. The settlement agreement was
approved by the FERC and paid by Anadarko during 2001. The settlement agreement
does not have any impact on the outstanding dispute between the Company and
PanEnergy in connection with the refunds that relate to the Cimmaron River
System. Anadarko's net income for 2001 included a $15 million charge (before
taxes) related to the settlement agreement. Discussions with the Kansas
Corporation Commission and PanEnergy to reach a settlement of the Cimmaron River
System dispute are ongoing. At this time, it is estimated that a resolution may
be reached in the first half of 2002, that may result in a payment by the
Company of about $7 million. Accordingly, a provision for $7 million was charged
against income in 2001.
Other Litigation Anadarko's net income for 1997 included a $2 million charge
(before taxes) related to the Kansas ad valorem tax refunds. This charge
reflects all principal and interest which may be due at the conclusion of all
regulatory proceedings and litigation to parties other than PanEnergy. The
Company is currently unable to predict the final outcome of this matter and no
additional provision for liability has been made in the accompanying financial
statements.
LEASE AGREEMENT The Company, through one of its affiliates, is a party to a
lease agreement (base lease) for the leveraged lease financing of the Corpus
Christi West Plant Refinery (West Plant) with an initial term expiring December
31, 2003, and successive renewal periods lasting through January 31, 2011. At
the conclusion of the initial term of the base lease, any renewal period or
January 31, 2011, the Company has the right to purchase the West Plant at the
fair market sales value. In connection with the sale by RME of its refining
business in 1987 and 1989, the West Plant was subleased to CITGO with sublease
payments during the initial term equal to the Company's base lease payments and
during any renewal period equal to the lesser of the base lease rental, which
will be tied to the annual fair market rental value or a specified maximum
amount. Additionally, CITGO has the option under the sublease to purchase the
West Plant from the Company at the conclusion of the initial term or any renewal
term at the fair market sales value, or on January 31, 2011 at a nominal price.
If the fair market rental value of the base lease during any renewal term
exceeds CITGO's maximum obligation under the sublease, or if CITGO purchases the
West Plant on January 31, 2011 and the fair market sales value of the West Plant
is greater than the purchase amount specified in the sublease, the Company will
be obligated to pay the excess amounts. The Company is unable at this time to
determine the fair market rental value or the fair market sales value of the
West Plant, but will at least annually evaluate the potential effect of the
obligation.
GUARANTEES Anadarko is guarantor for certain obligations of its wholly-owned
and consolidated subsidiaries, which are included in the consolidated financial
statements and notes. In addition, the Company is guarantor for specific
financial obligations of two trona mining affiliates. The investments in these
entities, which are not consolidated subsidiaries, are accounted for using the
equity method. The Company has guaranteed a portion of certain Industrial
Revenue Bonds, amounts due under a revolving credit agreement and letters of
credit required for environmental surety bonds. The amount the Company would be
obligated to pay should the affiliates default on these obligations would be up
to $8 million for environmental surety bonds and $35 million for debt.
ENRON The recent financial problems of Enron have had no material adverse
effect on the Company. As of December 31, 2001, in connection with several
physical and financial contracts, the Company had $10 million, net, in accounts
payable to Enron North America and $1 million in accounts receivable from other
Enron
104
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
17. CONTINGENCIES (CONTINUED)
affiliates. All contracts have been terminated by Anadarko under the terms of
the agreements, and $1 million has been charged to expense in 2001. The Company,
through purchase accounting entries for the Berkley acquisition, had recorded
market value liabilities on four contracts with Enron which were being amortized
over the terms of the contract. Upon termination of these contracts in December
2001, the remaining liability of $12 million was no longer required and was
recorded as income in 2001.
OTHER In connection with a sale of properties, the Company has agreed to
indemnify the purchaser for the use of certain currency remeasurement losses
utilized by the Company in previously filed tax returns, which are currently
being evaluated by the Guatemalan taxing authorities. The Company believes it is
probable that these losses will be disallowed by the Guatemalan taxing
authorities and will have to be settled with the purchaser in cash. The Company
has a $22 million liability recorded for the contingency.
18. SUBSEQUENT EVENTS
In February 2002, the Company issued $650 million principal amount of
5 3/8% Notes due March 2007. In March 2002, the Company issued $400 million
principal amount of 6 1/8% Notes due March 2012. The net proceeds from these
issuances were used to reduce floating-rate debt and to fund a portion of the
ZYP-CODES put to the Company. In March 2002, ZYP-CODES in the amount of $620
million were put to the Company for repayment and were paid in cash.
105
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(UNAUDITED)
QUARTERLY FINANCIAL DATA
The following table shows summary quarterly financial data for 2001 and
2000.
<Table>
<Caption>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
MILLIONS EXCEPT PER SHARE AMOUNTS ------- ------- ------- -------
2001
Revenues $3,009 $2,238 $1,743 $1,379
Operating income (loss), pretax 989(1) 637(2) (2,160)(3) 216(4)
Net income (loss) before cumulative effect of change in
accounting principle $ 664(1) $ 402(2) $(1,351)(3) $ 109(4)
Net income (loss) available to common stockholders before
cumulative effect of change in accounting principle $ 661(1) $ 401(2) $(1,353)(3) $ 108(4)
Net income (loss) available to common stockholders $ 656(1) $ 401(2) $(1,353)(3) $ 108(4)
EPS - before cumulative effect of change in accounting
principle - basic $ 2.64(1) $ 1.60(2) $(5.41)(3) $ 0.43(4)
EPS - before cumulative effect of change in accounting
principle - diluted $ 2.52(1) $ 1.50(2) $(5.41)(3) $ 0.41(4)
EPS - basic $ 2.62(1) $ 1.60(2) $(5.41)(3) $ 0.43(4)
EPS - diluted $ 2.50(1) $ 1.50(2) $(5.41)(3) $ 0.41(4)
Average number common shares outstanding - basic 250 251 250 249
Average number common shares outstanding - diluted 263 268 250 266
2000
Revenues $ 611 $ 718 $1,820 $2,351
Operating income, pretax 119 137 493 670(5)
Net income before cumulative effect of change in accounting
principle $ 50 $ 67 $ 250 $ 457(5)
Net income available to common stockholders before
cumulative effect of change in accounting principle $ 48 $ 64 $ 247 $ 454(5)
Net income available to common stockholders $ 31 $ 64 $ 247 $ 454(5)
EPS - before cumulative effect of change in accounting
principle - basic $ 0.37 $ 0.50 $ 1.07 $ 1.82(5)
EPS - before cumulative effect of change in accounting
principle - diluted $ 0.37 $ 0.48 $ 1.03 $ 1.75(5)
EPS - basic $ 0.24 $ 0.50 $ 1.07 $ 1.82(5)
EPS - diluted $ 0.24 $ 0.48 $ 1.03 $ 1.75(5)
Average number common shares outstanding - basic 128 128 230 249
Average number common shares outstanding - diluted 131 138 241 261
</Table>
- ---------------
(1) Anadarko's first quarter 2001 operating income includes a non-cash charge of
$7 million ($4 million after taxes) related to impairments for exploration
activity in Ghana. Anadarko's net income before cumulative effect of change
in accounting principle excluding the impairments was $668 million and net
income available to common stockholders was $660 million, or $2.52 per
common share (diluted).
(2) Anadarko's second quarter 2001 operating income includes a non-cash charge
of $8 million ($5 million after taxes) related to impairments for
exploration activity in the United Kingdom. Anadarko's net income excluding
the impairments was $407 million and net income available to common
stockholders was $406 million, or $1.52 per common share (diluted).
(3) Anadarko's operating loss for the third quarter 2001 includes a non-cash
charge of $2.53 billion ($1.57 billion after taxes) for impairments of the
carrying value of proved oil and gas properties primarily in the United
States, Canada and Argentina as a result of low oil and gas prices at the
end of the quarter. Anadarko's net income excluding the impairments was $215
million and net income available to common stockholders excluding the
impairments was $213 million, or $0.81 per common share (diluted).
(4) Anadarko's fourth quarter 2001 operating income includes a non-cash charge
of $3 million ($2 million after taxes) related to impairments for
exploration activity in the United Kingdom. Anadarko's net income excluding
the impairments was $111 million and net income available to common
stockholders was $110 million, or $0.42 per common share (diluted).
(5) Anadarko's fourth quarter 2000 operating income includes a non-cash charge
of $50 million ($32 million after income taxes) related to impairments for
exploration activities in the United Kingdom, Tunisia and other
international locations. Anadarko's net income excluding the impairments was
$489 million and net income available to common stockholders was $486
million, or $1.87 per common share (diluted).
106
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
The following is historical revenue and cost information relating to the
Company's oil and gas activities.
COSTS EXCLUDED
Excluded from amounts subject to amortization as of December 31, 2001 and
2000 are $3.57 billion and $2.90 billion, respectively, of costs associated with
unevaluated properties and major development projects. The majority of the
evaluation activities are expected to be completed within five to ten years.
COSTS EXCLUDED BY YEAR INCURRED
<Table>
<Caption>
YEAR COSTS INCURRED EXCLUDED
------------------------------ COSTS AT
PRIOR DEC. 31,
YEARS 1999 2000 2001 2001
millions ----- ---- ------ ------ --------
Property acquisition $29 $21 $1,217 $ 116 $1,383
Exploration 38 28 1,035 816 1,917
Capitalized interest 6 5 70 192 273
--- --- ------ ------ ------
Total $73 $54 $2,322 $1,124 $3,573
--- --- ------ ------ ------
</Table>
COSTS EXCLUDED BY COUNTRY
<Table>
<Caption>
OTHER
U.S. CANADA ALGERIA INTERNATIONAL TOTAL
millions ------ ------ ------- ------------- ------
Property acquisition $1,334 $ 49 $ -- $ -- $1,383
Exploration 1,200 503 -- 214 1,917
Capitalized interest 226 40 -- 7 273
------ ----- ---- ---- ------
Total $2,760 $ 592 $ -- $221 $3,573
------ ----- ---- ---- ------
</Table>
CHANGES IN COSTS EXCLUDED BY COUNTRY
<Table>
<Caption>
OTHER
U.S. CANADA ALGERIA INTERNATIONAL TOTAL
millions ------ ------ ------- ------------- ------
DECEMBER 31, 1999 $ 210 $ -- $ 62 $ 51 $ 323
Additional costs incurred in 2000 2,213 453 4 164 2,834
Costs transferred to DD&A pool in 2000 (115) (41) (51) (52) (259)
------ ----- ---- ---- ------
DECEMBER 31, 2000 2,308 412 15 163 2,898
Additional costs incurred in 2001 939 528 1 96 1,564
Costs transferred to DD&A pool in 2001 (487) (348) (16) (38) (889)
------ ----- ---- ---- ------
DECEMBER 31, 2001 $2,760 $ 592 $ -- $221 $3,573
------ ----- ---- ---- ------
</Table>
107
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
<Table>
<Caption>
2001 2000
millions ------- -------
UNITED STATES
Capitalized
Unproved properties $ 2,760 $ 2,308
Proved properties 10,464 8,667
------- -------
13,224 10,975
Accumulated depreciation, depletion and amortization 5,007 2,506
------- -------
Net capitalized costs 8,217 8,469
------- -------
CANADA
Capitalized
Unproved properties 592 412
Proved properties 2,493 1,200
------- -------
3,085 1,612
Accumulated depreciation, depletion and amortization 1,086 77
------- -------
Net capitalized costs 1,999 1,535
------- -------
ALGERIA
Capitalized
Unproved properties -- 15
Proved properties 907 704
------- -------
907 719
Accumulated depreciation, depletion and amortization 106 79
------- -------
Net capitalized costs 801 640
------- -------
OTHER INTERNATIONAL
Capitalized
Unproved properties 221 163
Proved properties 610 562
------- -------
831 725
Accumulated depreciation, depletion and amortization 83 39
------- -------
Net capitalized costs 748 686
------- -------
TOTAL
Capitalized
Unproved properties 3,573 2,898
Proved properties 14,474 11,133
------- -------
18,047 14,031
Accumulated depreciation, depletion and amortization 6,282 2,701
------- -------
Net capitalized costs $11,765 $11,330
------- -------
</Table>
108
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<Table>
<Caption>
2001 2000 1999
millions ------ ------ ----
UNITED STATES -- Capitalized
Property acquisition
Exploration $ 156 $1,897 $ 41
Development 31 2,984 50
Exploration 840 353 160
Development 1,196 777 304
------ ------ ----
2,223 6,011 555
------ ------ ----
CANADA -- Capitalized
Property acquisition
Exploration 309 437 --
Development 835 1,075 --
Exploration 223 16 --
Development 233 89 --
------ ------ ----
1,600 1,617 --
------ ------ ----
ALGERIA -- Capitalized
Property acquisition
Exploration -- -- 1
Exploration 2 7 13
Development 179 155 49
------ ------ ----
181 162 63
------ ------ ----
OTHER INTERNATIONAL -- Capitalized
Property acquisition
Exploration 30 122 1
Development 67 532 --
Exploration 65 39 34
Development 136 33 --
------ ------ ----
298 726 35
------ ------ ----
TOTAL -- Capitalized
Property acquisition
Exploration 495 2,456 43
Development 933 4,591 50
Exploration 1,130 415 207
Development 1,744 1,054 353
------ ------ ----
$4,302 $8,516 $653
------ ------ ----
</Table>
109
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
The following schedule includes only the revenues from the production and
sale of gas, oil, condensate and NGLs. Results of operations from gas, oil and
NGLs marketing and gas gathering are excluded. The income tax expense is
calculated by applying the current statutory tax rates to the revenues after
deducting costs, which include depreciation, depletion and amortization (DD&A)
allowances, after giving effect to permanent differences. The results of
operations exclude general office overhead and interest expense attributable to
oil and gas activities.
<Table>
<Caption>
2001 2000 1999
millions ------ ------ -----
UNITED STATES
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $2,041 $1,319 $ 261
Gas and oil sold to consolidated affiliates 1,344 748 314
------ ------ -----
3,385 2,067 575
Production (lifting) costs 662 406 185
Depreciation, depletion and amortization* 792 429 178
Impairments related to oil and gas properties 1,701 -- --
------ ------ -----
230 1,232 212
Income tax expense 60 429 75
------ ------ -----
Results of operations $ 170 $ 803 $ 137
------ ------ -----
*DD&A rate per net equivalent barrel $ 5.54 $ 5.16 $4.11
------ ------ -----
CANADA
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $ 755 $ 332 $ --
------ ------ -----
755 332 --
Production (lifting) costs 188 85 --
Depreciation, depletion and amortization* 225 76 --
Impairments related to oil and gas properties 808 -- --
------ ------ -----
(466) 171 --
Income tax expense (200) 68 --
------ ------ -----
Results of operations $ (266) $ 103 $ --
------ ------ -----
*DD&A rate per net equivalent barrel $ 6.62 $ 6.12 $ --
------ ------ -----
ALGERIA
Net revenues from production
Third-party sales of oil $ 59 $ 85 $ 48
Oil sold to consolidated affiliates 136 186 65
------ ------ -----
195 271 113
Production (lifting) costs 21 23 11
Depreciation, depletion and amortization* 24 26 18
------ ------ -----
150 222 84
Income tax expense 57 137 52
------ ------ -----
Results of operations $ 93 $ 85 $ 32
------ ------ -----
*DD&A rate per net equivalent barrel $ 3.00 $ 2.78 $2.96
------ ------ -----
</Table>
110
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (CONTINUED)
<Table>
<Caption>
2001 2000 1999
millions ------ ------ -----
OTHER INTERNATIONAL
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $ 193 $ 133 $ --
------ ------ -----
193 133 --
Production (lifting) costs 79 61 --
Depreciation, depletion and amortization* 69 39 --
Impairments related to oil and gas properties 37 50 24
------ ------ -----
8 (17) (24)
Income tax expense -- (9) (9)
------ ------ -----
Results of operations $ 8 $ (8) $ (15)
------ ------ -----
*DD&A rate per net equivalent barrel $ 5.31 $ 5.36 $ n/a
------ ------ -----
TOTAL
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $3,048 $1,869 $ 309
Gas and oil sold to consolidated affiliates 1,480 934 379
------ ------ -----
4,528 2,803 688
Production (lifting) costs 950 575 196
Depreciation, depletion and amortization* 1,110 570 196
Impairments related to oil and gas properties 2,546 50 24
------ ------ -----
(78) 1,608 272
Income tax expense (83) 625 118
------ ------ -----
Results of operations $ 5 $ 983 $ 154
------ ------ -----
*DD&A rate per net equivalent barrel $ 5.61 $ 5.08 $3.97
------ ------ -----
</Table>
- ---------------
In July 2000, Anadarko acquired its producing activities in Canada and other
international areas as a result of the merger with RME.
111
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
OIL AND GAS RESERVES
The following table shows internal estimates prepared by the Company's
engineers of proved reserves and proved developed reserves, net of royalty
interests, of natural gas, crude oil, condensate and NGLs owned at year-end and
changes in proved reserves during the last three years. Volumes for natural gas
are in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per
square inch and volumes for oil, condensate and NGLs are in millions of barrels
(MMBbls). Total volumes are in millions of barrels of oil equivalent (MMBOE).
For this computation, one barrel is the equivalent of six thousand cubic feet of
gas. NGLs are included with oil and condensate reserves and the associated
shrinkage has been deducted from the gas reserves.
Algerian reserves are shown in accordance with the PSA. The reserves
include estimated quantities allocated to Anadarko for recovery of costs and
Algerian taxes and Anadarko's net equity share after recovery of such costs.
The Company's reserves increased in 2001 primarily from exploration and
development drilling and the Berkley and Gulfstream acquisitions, offset in part
by production, divestitures and downward revisions to prior estimates due to low
year-end prices. The Company's reserves increased in 2000 primarily from the
merger transaction with RME, exploration and development drilling, improved
recovery and high gas prices at year-end 2000 compared to year-end 1999.
Anadarko's reserves increased in 1999 primarily due to exploration and
development drilling and due to significantly higher crude oil and slightly
higher natural gas prices at year-end 1999 compared to year-end 1998.
The Company emphasizes that the volumes of reserves shown below are
estimates which, by their nature, are subject to revision. The estimates are
made using all available geological and reservoir data as well as production
performance data. These estimates are reviewed and revised, either upward or
downward, as warranted by additional data. Revisions are necessary due to
changes in assumptions based on, among other things, reservoir performance,
prices, economic conditions and governmental restrictions. Decreases in prices,
for example, may cause a reduction in some proved reserves due to uneconomic
conditions.
112
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
OIL AND GAS RESERVES (CONTINUED)
<Table>
<Caption>
NATURAL GAS OIL, CONDENSATE AND NGLS
(BCF) (MMBBLS)
------------------------------ ---------------------------------------
OTHER OTHER
U.S. CANADA INT'L TOTAL U.S. CANADA ALGERIA INT'L TOTAL
----- ------ ----- ----- ---- ------ ------- ----- -----
PROVED RESERVES
DECEMBER 31, 1998 2,647 -- -- 2,647 249 -- 245 -- 494
Revisions of prior estimates (188) -- -- (188) 40 -- -- -- 40
Extensions, discoveries and other
additions 112 -- -- 112 1 -- 73 -- 74
Improved recovery 34 -- -- 34 10 -- -- -- 10
Purchases in place 99 -- -- 99 1 -- -- -- 1
Sales in place (27) -- -- (27) (2) -- (23) -- (25)
Production (170) -- -- (170) (15) -- (6) -- (21)
----- ----- --- ----- --- --- --- --- -----
DECEMBER 31, 1999 2,507 -- -- 2,507 284 -- 289 -- 573
Revisions of prior estimates 102 (30) (5) 67 23 (5) -- 6 24
Extensions, discoveries and other
additions 665 15 -- 680 8 3 84 -- 95
Improved recovery 30 -- -- 30 9 -- -- -- 9
Purchases in place 2,253 910 33 3,196 161 85 -- 147 393
Sales in place -- (2) -- (2) -- -- -- (1) (1)
Production (338) (46) (1) (385) (27) (4) (9) (7) (47)
----- ----- --- ----- --- --- --- --- -----
DECEMBER 31, 2000 5,219 847 27 6,093 458 79 364 145 1,046
Revisions of prior estimates (172) (17) -- (189) (23) (3) (12) 15 (23)
Extensions, discoveries and other
additions 1,186 171 -- 1,357 91 8 44 30 173
Improved recovery (9) 2 -- (7) (5) 9 -- -- 4
Purchases in place 2 407 146 555 1 30 -- 33 64
Sales in place (5) (48) (26) (79) (1) (1) -- (45) (47)
Production (573) (121) (1) (695) (48) (14) (9) (14) (85)
----- ----- --- ----- --- --- --- --- -----
DECEMBER 31, 2001 5,648 1,241 146 7,035 473 108 387 164 1,132
----- ----- --- ----- --- --- --- --- -----
PROVED DEVELOPED RESERVES
December 31, 1998 1,640 -- -- 1,640 120 -- 44 -- 164
December 31, 1999 1,672 -- -- 1,672 134 -- 61 -- 195
December 31, 2000 4,424 720 16 5,160 355 59 98 85 597
December 31, 2001 4,247 1,028 -- 5,275 321 79 154 72 626
</Table>
113
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (CONTINUED)
(UNAUDITED)
OIL AND GAS RESERVES (CONTINUED)
<Table>
<Caption>
TOTAL
(MMBOE)
----------------------------------------
OTHER
U.S. CANADA ALGERIA INT'L TOTAL
----- ------ ------- ----- -----
PROVED RESERVES
DECEMBER 31, 1998 690 -- 245 -- 935
Revisions of prior estimates 9 -- -- -- 9
Extensions, discoveries and other additions 19 -- 73 -- 92
Improved recovery 16 -- -- -- 16
Purchases in place 18 -- -- -- 18
Sales in place (6) -- (23) -- (29)
Production (44) -- (6) -- (50)
----- --- --- --- -----
DECEMBER 31, 1999 702 -- 289 -- 991
Revisions of prior estimates 39 (10) -- 6 35
Extensions, discoveries and other additions 118 6 84 -- 208
Improved recovery 14 -- -- -- 14
Purchases in place 537 237 -- 152 926
Sales in place -- -- -- (1) (1)
Production (83) (13) (9) (7) (112)
----- --- --- --- -----
DECEMBER 31, 2000 1,327 220 364 150 2,061
Revisions of prior estimates (52) (6) (12) 15 (55)
Extensions, discoveries and other additions 290 36 44 30 400
Improved recovery (6) 9 -- -- 3
Purchases in place 1 99 -- 57 157
Sales in place (1) (9) -- (50) (60)
Production (144) (34) (9) (14) (201)
----- --- --- --- -----
DECEMBER 31, 2001 1,415 315 387 188 2,305
----- --- --- --- -----
PROVED DEVELOPED RESERVES
December 31, 1998 393 -- 44 -- 437
December 31, 1999 412 -- 61 -- 473
December 31, 2000 1,092 179 98 88 1,457
December 31, 2001 1,029 250 154 72 1,505
</Table>
114
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
DISCOUNTED FUTURE NET CASH FLOWS
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and NGLs were made in accordance with SFAS No. 69, "Disclosures about
Oil and Gas Producing Activities." The amounts were prepared by the Company's
engineers and are shown in the following table. The estimates are based on
prices at year-end. Gas prices are escalated only for fixed and determinable
amounts under provisions in some contracts. Estimated future cash inflows are
reduced by estimated future development and production costs based on year-end
cost levels, assuming continuation of existing economic conditions, and by
estimated future income tax expense. Income tax expense, both U.S. and foreign,
is calculated by applying the existing statutory tax rates, including any known
future changes, to the pretax net cash flows giving effect to any permanent
differences and reduced by the applicable tax basis. The effect of tax credits
is considered in determining the income tax expense.
At December 31, 2001, the present value (discounted at 10%) of future net
revenues from Anadarko's proved reserves was $11.54 billion, before income
taxes, and $8.03 billion, after income taxes, (stated in accordance with the
regulations of the SEC and the Financial Accounting Standards Board). The after
income taxes decrease of $13.37 billion or 62% in 2001 compared to 2000 is
primarily due to significantly lower natural gas and crude oil prices at
year-end 2001, partially offset by additions of proved reserves related to
successful drilling worldwide and the Berkley and Gulfstream acquisitions.
The present value of future net revenues does not purport to be an estimate
of the fair market value of Anadarko's proved reserves. An estimate of fair
value would also take into account, among other things, anticipated changes in
future prices and costs, the expected recovery of reserves in excess of proved
reserves and a discount factor more representative of the time value of money
and the risks inherent in producing oil and gas. Significant changes in
estimated reserve volumes or commodity prices could have a material effect on
the Company's consolidated financial statements.
Under the full cost method of accounting, a non-cash charge to earnings
related to the carrying value of the Company's oil and gas properties on a
country-by-country basis may be required when prices are low. Whether the
Company will be required to take such a charge depends on the prices for crude
oil and natural gas at the end of any quarter, as well as the effect of both
capital expenditures and changes to proved reserves during that quarter. If a
non-cash charge were required, it would reduce earnings for the period and
result in lower DD&A expense in future periods.
As a result of low oil and gas prices at September 30, 2001, Anadarko's
capitalized costs of oil and gas properties in the United States, Canada and
Argentina exceeded the ceiling limitation, and the Company recorded a $2.53
billion ($1.57 billion after taxes) non-cash write-down in the third quarter of
2001. The pre-tax write-down is reflected as additional accumulated DD&A in the
Company's balance sheet.
115
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
<Table>
<Caption>
2001 2000 1999
MILLIONS ------- ------- -------
UNITED STATES
Future cash inflows $19,890 $57,027 $11,012
Future production and development costs 7,831 9,357 3,232
------- ------- -------
Future net cash flows before income taxes 12,059 47,670 7,780
10% annual discount for estimated timing of cash flows 5,805 22,911 3,916
------- ------- -------
Discounted future net cash flows before income taxes 6,254 24,759 3,864
Future income taxes, net of 10% annual discount 1,764 8,546 1,070
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 4,490 16,213 2,794
------- ------- -------
CANADA
Future cash inflows 4,325 8,720 --
Future production and development costs 1,590 1,154 --
------- ------- -------
Future net cash flows before income taxes 2,735 7,566 --
10% annual discount for estimated timing of cash flows 1,030 3,261 --
------- ------- -------
Discounted future net cash flows before income taxes 1,705 4,305 --
Future income taxes, net of 10% annual discount 465 1,880 --
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 1,240 2,425 --
------- ------- -------
ALGERIA
Future cash inflows 7,466 8,410 7,259
Future production and development costs 1,426 1,419 1,077
------- ------- -------
Future net cash flows before income taxes 6,040 6,991 6,182
10% annual discount for estimated timing of cash flows 3,089 3,807 3,683
------- ------- -------
Discounted future net cash flows before income taxes 2,951 3,184 2,499
Future income taxes, net of 10% annual discount 1,109 1,108 911
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 1,842 2,076 1,588
------- ------- -------
OTHER INTERNATIONAL
Future cash inflows 2,242 2,631 --
Future production and development costs 1,049 1,031 --
------- ------- -------
Future net cash flows before income taxes 1,193 1,600 --
10% annual discount for estimated timing of cash flows 562 705 --
------- ------- -------
Discounted future net cash flows before income taxes 631 895 --
Future income taxes, net of 10% annual discount 172 204 --
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 459 691 --
------- ------- -------
TOTAL
Future cash inflows 33,923 76,788 18,271
Future production and development costs 11,896 12,961 4,309
------- ------- -------
Future net cash flows before income taxes 22,027 63,827 13,962
10% annual discount for estimated timing of cash flows 10,486 30,684 7,599
------- ------- -------
Discounted future net cash flows before income taxes 11,541 33,143 6,363
Future income taxes, net of 10% annual discount 3,510 11,738 1,981
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 8,031 $21,405 $ 4,382
------- ------- -------
</Table>
116
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
<Table>
<Caption>
2001 2000 1999
millions -------- ------- -------
UNITED STATES
Beginning of year $ 16,213 $ 2,794 $ 1,796
Sales and transfers of oil and gas produced, net of
production costs (2,724) (1,661) (390)
Net changes in prices and development and production costs (19,126) 7,437 1,451
Extensions, discoveries, additions and improved recovery,
less related costs 624 2,719 (90)
Development costs incurred during the period 337 126 30
Revisions of previous quantity estimates (453) 114 175
Purchases of minerals in place 17 11,841 52
Sales of minerals in place (5) (1) (22)
Accretion of discount 2,476 386 249
Net change in income taxes 6,782 (7,476) (372)
Other 349 (66) (85)
-------- ------- -------
End of year 4,490 16,213 2,794
-------- ------- -------
CANADA
Beginning of year 2,425 -- --
Sales and transfers of oil and gas produced, net of
production costs (567) (247) --
Net changes in prices and development and production costs (3,317) -- --
Extensions, discoveries, additions and improved recovery,
less related costs 279 101 --
Development costs incurred during the period 101 -- --
Revisions of previous quantity estimates (38) (165) --
Purchases of minerals in place 593 4,568 --
Sales of minerals in place (56) -- --
Accretion of discount 431 -- --
Net change in income taxes 1,415 (1,880) --
Other (26) 48 --
-------- ------- -------
End of year 1,240 2,425 --
-------- ------- -------
ALGERIA
Beginning of year 2,076 1,588 426
Sales and transfers of oil produced, net of production costs (174) (248) (102)
Net changes in prices and development and production costs (554) (330) 1,774
Extensions, discoveries, additions and improved recovery,
less related costs 56 901 210
Development costs incurred during the period 164 135 38
Sales of minerals in place -- -- (85)
Accretion of discount 318 250 64
Net change in income taxes (1) (197) (697)
Other (43) (23) (40)
-------- ------- -------
End of year $ 1,842 $ 2,076 $ 1,588
-------- ------- -------
</Table>
117
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES (CONTINUED)
<Table>
<Caption>
2001 2000 1999
millions -------- ------- -------
OTHER INTERNATIONAL
Beginning of year $ 691 $ -- $ --
Sales and transfers of oil and gas produced, net of
production costs (113) (72) --
Net changes in prices and development and production costs (370) -- --
Extensions, discoveries, additions and improved recovery,
less related costs 109 -- --
Development costs incurred during the period 87 -- --
Revisions of previous quantity estimates 75 -- --
Purchases of minerals in place 188 967 --
Sales of minerals in place (199) -- --
Accretion of discount 90 -- --
Net change in income taxes 32 (204) --
Other (131) -- --
-------- ------- -------
End of year 459 691 --
-------- ------- -------
TOTAL
Beginning of year 21,405 4,382 2,222
Sales and transfers of oil and gas produced, net of
production costs (3,578) (2,228) (492)
Net changes in prices and development and production costs (23,367) 7,107 3,225
Extensions, discoveries, additions and improved recovery,
less related costs 1,068 3,721 120
Development costs incurred during the period 689 261 68
Revisions of previous quantity estimates (416) (51) 175
Purchases of minerals in place 798 17,376 52
Sales of minerals in place (260) (1) (107)
Accretion of discount 3,315 636 313
Net change in income taxes 8,228 (9,757) (1,069)
Other 149 (41) (125)
-------- ------- -------
End of year $ 8,031 $21,405 $ 4,382
-------- ------- -------
</Table>
118
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
See Anadarko Board of Directors and Section 16(a) Beneficial Ownership
Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement,
dated March 25, 2002 (Proxy Statement), which is incorporated herein by
reference.
See list of Executive Officers of the Registrant appearing under Item 4 of
this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
See Anadarko Board of Directors -- Director Compensation and Compensation
and Benefits Committee Report on 2001 Executive Compensation in the Proxy
Statement, which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
See Stock Ownership in the Proxy Statement, which is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Transactions with Management in the Proxy Statement, which is
incorporated herein by reference.
119
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report or
incorporated by reference:
(1) The consolidated financial statements of Anadarko Petroleum
Corporation are listed on the Index to this report, page 61.
(2) Exhibits not incorporated by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits
not so designated are incorporated herein by reference to a prior
filing as indicated.
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ---------------------------------------- ------------------------------- ---------
2(a) Agreement and Plan of Merger dated as of 2.1 to Form 8-K dated April 2, 1-8968
April 2, 2000, among Anadarko, Subcorp 2000
and RME
3(a) Restated Certificate of Incorporation of 4(a) to Form S-3 dated May 9, 333-60496
Anadarko Petroleum Corporation, dated 2001
August 28, 1986
(b) By-laws of Anadarko Petroleum 3(e) to Form 10-Q for quarter 1-8968
Corporation, as amended ended September 30, 2000
(c) Certificate of Amendment of Anadarko's 4.1 to Form 8-K dated July 28, 1-8968
Restated Certificate of Incorporation 2000
4(a) Certificate of Designation of 5.46% 4(a) to Form 8-K dated May 6, 1-8968
Cumulative Preferred Stock, Series B 1998
(b) Rights Agreement, dated as of October 4.1 to Form 8-A dated October 1-8968
29, 1998, between Anadarko Petroleum 30, 1998
Corporation and The Chase Manhattan Bank
(c) Amendment No. 1 to Rights Agreement, 2.4 to Form 8-K dated April 2, 1-8968
dated as of April 2, 2000 between 2000
Anadarko and the Rights Agent
DIRECTOR AND EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
10(b) (i) Director Deferred Compensation Plan of 10(b)(viii) to Form 10-K for 1-8968
Anadarko Petroleum Corporation, year ended December 31, 1986
effective January 1, 1987
(ii) Amendment to Anadarko Petroleum 10(b)(ii) to Form 10-K for year 1-8968
Corporation Director Deferred ended December 31, 1997
Compensation Plan
(iii) Director Deferred Compensation Agreement 19(a)(i) to Form 10-Q for 1-8968
between Anadarko Petroleum Corporation quarter ended March 31, 1987
and each Director Electing to
Participate
(iv) First Amendment to Director Deferred 10(b)(iv) to Form 10-K for year 1-8968
Compensation Agreement 1987, 1988, 1989 ended December 31, 1997
and 1990 Plan Years
(v) Termination of Director Deferred 10(b)(v) to Form 10-K 1-8968
Compensation Plan of Anadarko Petroleum for year ended
Corporation, effective July 11, 2000 December 31, 2000
</Table>
120
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ---------------------------------------- ------------------------------- ---------
10(b) (vi) Anadarko Petroleum Corporation 1988 19(b) to Form 10-Q for quarter 1-8968
Stock Option Plan for Non-Employee ended September 30, 1988
Directors
(vii) Anadarko Petroleum Corporation Amended 99 -- Attachment A to Form 10-K 1-8968
and Restated 1988 Stock Option Plan for for year ended December 31,
Non-Employee Directors 1993
(viii) Amendment to Anadarko Petroleum 10(b)(vii) to Form 10-K for 1-8968
Corporation 1988 Stock Option Plan for year ended December 31, 1997
Non-Employee Directors
(ix) Second Amendment to Anadarko Petroleum 10(b)(viii) to Form 10-K for 1-8968
Corporation 1988 Stock Option Plan for year ended December 31, 1997
Non-Employee Directors
(x) 1998 Director Stock Plan of Anadarko 99 -- Attachment A to Form 10-K 1-8968
Petroleum Corporation, effective January for year ended December 31,
30, 1998 1997
(xi) Anadarko Petroleum Corporation and 19(c)(ix) to Form 10-Q for 1-8968
Participating Affiliates and quarter ended September 30,
Subsidiaries Annual Override Pool Bonus 1986
Plan, as amended October 6, 1986
(xii) Second Amendment to Anadarko Petroleum 10(b)(ii) to Form 10-K for year 1-8968
Corporation and Participating Affiliates ended December 31, 1987
and Subsidiaries Annual Override Pool
Bonus Plan
(xiii) Restatement of the Anadarko Petroleum Post Effective Amendment No. 1 33-22134
Corporation 1987 Stock Option Plan (and to Forms S-8 and S-3, Anadarko
Related Agreement) Petroleum Corporation 1987
Stock Option Plan
(xiv) First Amendment to Restatement of the 10(b)(xii) to Form 10-K for 1-8968
Anadarko Petroleum Corporation 1987 year ended December 31, 1997
Stock Option Plan
(xv) 1993 Stock Incentive Plan 10(b)(xii) to Form 10-K for 1-8968
year ended December 31, 1993
(xvi) First Amendment to Anadarko Petroleum 99 -- Attachment A to Form 10-K 1-8968
Corporation 1993 Stock Incentive Plans for year ended December 31,
1996
(xvii) Second Amendment to Anadarko Petroleum 10(b)(xv) to Form 10-K for year 1-8968
Corporation 1993 Stock Incentive Plan ended December 31, 1997
(xviii) Anadarko Petroleum Corporation 1993 10(a) to Form 10-Q for quarter 1-8968
Stock Incentive Plan Stock Option ended March 31, 1996
Agreement
(xix) Form of Anadarko Petroleum Corporation 10(b)(xvii) to Form 10-K for 1-8968
1993 Stock Incentive Plan Stock Option year ended December 31, 1997
Agreement
(xx) Form of Anadarko Petroleum Corporation 10(b)(xviii) to Form 10-K for 1-8968
1993 Stock Incentive Plan Restricted year ended December 31, 1997
Stock Agreement
</Table>
121
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ---------------------------------------- ------------------------------- ---------
10(b) (xxi) Anadarko Petroleum Corporation 1999 99 -- Attachment A to Form 10-K 1-8968
Stock Incentive Plan for year ended December 31,
1998
(xxii) Amendment to 1999 Stock Incentive Plan, 10(b)(xxii) to Form 10-K for 1-8968
as of July 1, 2000 year ended December 31, 2000
(xxiii) Form of Anadarko Petroleum Corporation 10(b)(xxiii) to Form 10-K for 1-8968
1999 Stock Incentive Plan Stock Option year ended December 31, 1999
Agreement
(xxiv) Form of Anadarko Petroleum Corporation 10(b)(xxiv) to Form 10-K for 1-8968
1999 Stock Incentive Plan Restricted year ended December 31, 1999
Stock Agreement
(xxv) Annual Incentive Bonus Plan 10(b)(xiii) to Form 10-K for 1-8968
year ended December 31, 1993
(xxvi) First Amendment to Anadarko Petroleum 99 -- Attachment B to Form 10-K 1-8968
Corporation Annual Incentive Bonus Plan for year ended December 31,
1998
(xxvii) Key Employee Change of Control Contract 10(b)(xxii) to Form 10-K for 1-8968
year ended December 31, 1997
(xxviii) First Amendment to Anadarko Petroleum 10(b) to Form 10-Q for quarter 1-8968
Corporation Key Employee Change of ended September 30, 2000
Control Contract
(xxix) Executive Deferred Compensation Plan of 10(b)(xii) to Form 10-K for 1-8968
Anadarko Petroleum Corporation and year ended December 31, 1987
Participating Subsidiaries and
Affiliates, effective October 1, 1986
(xxx) Executive Deferred Compensation Plan of 10(b)(vi) to Form 10-K for year 1-8968
Anadarko Petroleum Corporation, ended December 31, 1986
effective January 1, 1987
(xxxi) Amendment to Anadarko Petroleum 10(b)(xxv) to Form 10-K for 1-8968
Corporation Executive Deferred year ended December 31, 1997
Compensation Plan
(xxxii) Executive Deferred Compensation 19(a)(ii) to Form 10-Q for 1-8968
Agreement between Anadarko Petroleum quarter ended March 31, 1987
Corporation and each Executive Electing
to Participate
(xxxiii) First Amendment to Executive Deferred 10(b)(xxvii) to Form 10-K for 1-8968
Compensation Agreement 1987, 1988, 1989 year ended December 31, 1997
and 1990 Plan Years
(xxxiv) Amendments to Executive Deferred 10(b)(xv) to Form 10-K for year 1-8968
Compensation Agreement between Anadarko ended December 31, 1987
Petroleum Corporation and each Executive
Electing to Participate
(xxxv) Termination of Executive Deferred 10(b)(xxxv) to Form 10-K for 1-8968
Compensation Plan of Anadarko Petroleum year ended December 31, 2000
Corporation, effective July 11, 2000
(xxxvi) Anadarko Retirement Restoration Plan, 10(b)(xix) to Form 10-K for 1-8968
effective January 1, 1995 year ended December 31, 1995
</Table>
122
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ---------------------------------------- ------------------------------- ---------
10(b) (xxxvii) Anadarko Savings Restoration Plan, 10(b)(xx) to Form 10-K for year 1-8968
effective January 1, 1995 ended December 31, 1995
(xxxviii) Amendment to Amended and Restated 10(b)(xxxi) to Form 10-K 1-8968
Anadarko Savings Restoration Plan for year ended December 31,
1997
(xxxix) Plan Agreement for the Management Life 10(b)(xxi) to Form 10-K for 1-8968
Insurance Plan between Anadarko year ended December 31, 1995
Petroleum Corporation and each Eligible
Employee, effective July 1, 1995
(xl) Anadarko Petroleum Corporation Estate 10(b)(xxxiv) to Form 10-K for 1-8968
Enhancement Program year ended December 31, 1998
(xli) Estate Enhancement Program Agreement 10(b)(xxxv) to Form 10-K for 1-8968
between Anadarko Petroleum Corporation year ended December 31, 1998
and Eligible Executives
(xlii) Estate Enhancement Program Agreements 10(b)(xxxxii) to Form 10-K 1-8968
effective November 29, 2000 for year ended December 31,
2000
(xliii) Employment Agreement 10(a) to Form 10-Q for quarter 1-8968
ended September 30, 2000
*12 Computation of Ratios of Earnings to
Fixed Charges and Earnings to Combined
Fixed Charges and Preferred Stock
Dividends
*21 List of Significant Subsidiaries
*23 Consents of Experts and Counsel Consent
of KPMG LLP
*24 Powers of Attorney
99 Anadarko Petroleum Corporation Proxy Filed on March 22, 2002
Statement, dated March 25, 2002
</Table>
- ---------------
The total amount of securities of the registrant authorized under any instrument
with respect to long-term debt not filed as an exhibit does not exceed 10% of
the total assets of the registrant and its subsidiaries on a consolidated basis.
The registrant agrees, upon request of the Securities and Exchange Commission,
to furnish copies of any or all of such instruments to the Securities and
Exchange Commission.
(b) REPORTS ON FORM 8-K
There were no reports filed on Form 8-K during the three months ended
December 31, 2001.
123
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.
ANADARKO PETROLEUM CORPORATION
March 22, 2002 By: MICHAEL E. ROSE
-------------------------------------
(Michael E. Rose, Executive Vice
President,
Finance and Chief Financial 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 AND IN THE CAPACITIES INDICATED ON MARCH 22, 2002.
<Table>
<Caption>
NAME AND SIGNATURE TITLE
------------------ -----
(i) Principal executive officer:*
JOHN N. SEITZ President and Chief Executive Officer
------------------------------------------------
(John N. Seitz)
(ii) Principal financial officer:*
MICHAEL E. ROSE Executive Vice President, Finance and Chief
------------------------------------------------ Financial Officer
(Michael E. Rose)
(iii) Principal accounting officer:*
JAMES R. LARSON Vice President and Controller
------------------------------------------------
(James R. Larson)
(iv) Directors:*
ROBERT J. ALLISON, JR.
CONRAD P. ALBERT
LARRY BARCUS
RONALD BROWN
JAMES L. BRYAN
JOHN R. BUTLER, JR.
PRESTON M. GEREN III
JOHN R. GORDON
GEORGE LINDAHL III
JOHN W. PODUSKA, SR.
JEFF D. SANDEFER
JOHN N. SEITZ
- -----
* Signed on behalf of each of these persons and on his own behalf:
By MICHAEL E. ROSE
---------------------------------------
(Michael E. Rose, Attorney-in-Fact )
</Table>
124
EXHIBIT INDEX
(a) The following documents are filed as a part of this report or
incorporated by reference:
(1) The consolidated financial statements of Anadarko Petroleum
Corporation are listed on the Index to this report, page 61.
(2) Exhibits not incorporated by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits
not so designated are incorporated herein by reference to a prior
filing as indicated.
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ------------------------------------------ ------------------------------- ---------
2(a) Agreement and Plan of Merger dated as of 2.1 to Form 8-K dated April 2, 1-8968
April 2, 2000, among Anadarko, Subcorp and 2000
RME
3(a) Restated Certificate of Incorporation of 4(a) to Form S-3 dated May 9, 333-60496
Anadarko Petroleum Corporation, dated 2001
August 28, 1986
(b) By-laws of Anadarko Petroleum Corporation, 3(e) to Form 10-Q for quarter 1-8968
as amended ended September 30, 2000
(c) Certificate of Amendment of Anadarko's 4.1 to Form 8-K dated July 28, 1-8968
Restated Certificate of Incorporation 2000
4(a) Certificate of Designation of 5.46% 4(a) to Form 8-K dated May 6, 1-8968
Cumulative Preferred Stock, Series B 1998
(b) Rights Agreement, dated as of October 29, 4.1 to Form 8-A dated October 1-8968
1998, between Anadarko Petroleum 30, 1998
Corporation and The Chase Manhattan Bank
(c) Amendment No. 1 to Rights Agreement, dated 2.4 to Form 8-K dated April 2, 1-8968
as of April 2, 2000 between Anadarko and 2000
the Rights Agent
DIRECTOR AND EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
10(b) (i) Director Deferred Compensation Plan of 10(b)(viii) to Form 10-K for 1-8968
Anadarko Petroleum Corporation, effective year ended December 31, 1986
January 1, 1987
(ii) Amendment to Anadarko Petroleum 10(b)(ii) to Form 10-K for year 1-8968
Corporation Director Deferred Compensation ended December 31, 1997
Plan
(iii) Director Deferred Compensation Agreement 19(a)(i) to Form 10-Q for 1-8968
between Anadarko Petroleum Corporation and quarter ended March 31, 1987
each Director Electing to Participate
(iv) First Amendment to Director Deferred 10(b)(iv) to Form 10-K for year 1-8968
Compensation Agreement 1987, 1988, 1989 ended December 31, 1997
and 1990 Plan Years
(v) Termination of Director Deferred 10(b)(v) to Form 10-K 1-8968
Compensation Plan of Anadarko Petroleum for year ended
Corporation, effective July 11, 2000 December 31, 2000
(vi) Anadarko Petroleum Corporation 1988 Stock 19(b) to Form 10-Q for quarter 1-8968
Option Plan for Non-Employee Directors ended September 30, 1988
(vii) Anadarko Petroleum Corporation Amended and 99 -- Attachment A to Form 10-K 1-8968
Restated 1988 Stock Option Plan for Non- for year ended December 31,
Employee Directors 1993
</Table>
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ------------------------------------------ ------------------------------- ---------
10(b) (viii) Amendment to Anadarko Petroleum 10(b)(vii) to Form 10-K for 1-8968
Corporation 1988 Stock Option Plan for year ended December 31, 1997
Non-Employee Directors
(ix) Second Amendment to Anadarko Petroleum 10(b)(viii) to Form 10-K for 1-8968
Corporation 1988 Stock Option Plan for year ended December 31, 1997
Non-Employee Directors
(x) 1998 Director Stock Plan of Anadarko 99 -- Attachment A to Form 10-K 1-8968
Petroleum Corporation, effective January for year ended December 31,
30, 1998 1997
(xi) Anadarko Petroleum Corporation and 19(c)(ix) to Form 10-Q for 1-8968
Participating Affiliates and Subsidiaries quarter ended September 30,
Annual Override Pool Bonus Plan, as 1986
amended October 6, 1986
(xii) Second Amendment to Anadarko Petroleum 10(b)(ii) to Form 10-K for year 1-8968
Corporation and Participating Affiliates ended December 31, 1987
and Subsidiaries Annual Override Pool
Bonus Plan
(xiii) Restatement of the Anadarko Petroleum Post Effective Amendment No. 1 33-22134
Corporation 1987 Stock Option Plan (and to Forms S-8 and S-3, Anadarko
Related Agreement) Petroleum Corporation 1987
Stock Option Plan
(xiv) First Amendment to Restatement of the 10(b)(xii) to Form 10-K for 1-8968
Anadarko Petroleum Corporation 1987 Stock year ended December 31, 1997
Option Plan
(xv) 1993 Stock Incentive Plan 10(b)(xii) to Form 10-K for 1-8968
year ended December 31, 1993
(xvi) First Amendment to Anadarko Petroleum 99 -- Attachment A to Form 10-K 1-8968
Corporation 1993 Stock Incentive Plans for year ended December 31,
1996
(xvii) Second Amendment to Anadarko Petroleum 10(b)(xv) to Form 10-K for year 1-8968
Corporation 1993 Stock Incentive Plan ended December 31, 1997
(xviii) Anadarko Petroleum Corporation 1993 Stock 10(a) to Form 10-Q for quarter 1-8968
Incentive Plan Stock Option Agreement ended March 31, 1996
(xix) Form of Anadarko Petroleum Corporation 10(b)(xvii) to Form 10-K for 1-8968
1993 Stock Incentive Plan Stock Option year ended December 31, 1997
Agreement
(xx) Form of Anadarko Petroleum Corporation 10(b)(xviii) to Form 10-K for 1-8968
1993 Stock Incentive Plan Restricted Stock year ended December 31, 1997
Agreement
(xxi) Anadarko Petroleum Corporation 1999 Stock 99 -- Attachment A to Form 10-K 1-8968
Incentive Plan for year ended December 31,
1998
(xxii) Amendment to 1999 Stock Incentive Plan, as 10(b)(xxii) to Form 10-K for 1-8968
of July 1, 2000 year ended December 31, 2000
(xxiii) Form of Anadarko Petroleum Corporation 10(b)(xxiii) to Form 10-K for 1-8968
1999 Stock Incentive Plan Stock Option year ended December 31, 1999
Agreement
</Table>
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ------------------------------------------ ------------------------------- ---------
10(b) (xxiv) Form of Anadarko Petroleum Corporation 10(b)(xxiv) to Form 10-K for 1-8968
1999 Stock Incentive Plan Restricted Stock year ended December 31, 1999
Agreement
(xxv) Annual Incentive Bonus Plan 10(b)(xiii) to Form 10-K for 1-8968
year ended December 31, 1993
(xxvi) First Amendment to Anadarko Petroleum 99 -- Attachment B to Form 10-K 1-8968
Corporation Annual Incentive Bonus Plan for year ended December 31,
1998
(xxvii) Key Employee Change of Control Contract 10(b)(xxii) to Form 10-K for 1-8968
year ended December 31, 1997
(xxviii) First Amendment to Anadarko Petroleum 10(b) to Form 10-Q for quarter 1-8968
Corporation Key Employee Change of Control ended September 30, 2000
Contract
(xxix) Executive Deferred Compensation Plan of 10(b)(xii) to Form 10-K for 1-8968
Anadarko Petroleum Corporation and year ended December 31, 1987
Participating Subsidiaries and Affiliates,
effective October 1, 1986
(xxx) Executive Deferred Compensation Plan of 10(b)(vi) to Form 10-K for year 1-8968
Anadarko Petroleum Corporation, effective ended December 31, 1986
January 1, 1987
(xxxi) Amendment to Anadarko Petroleum 10(b)(xxv) to Form 10-K for 1-8968
Corporation Executive Deferred year ended December 31, 1997
Compensation Plan
(xxxii) Executive Deferred Compensation Agreement 19(a)(ii) to Form 10-Q for 1-8968
between Anadarko Petroleum Corporation and quarter ended March 31, 1987
each Executive Electing to Participate
(xxxiii) First Amendment to Executive Deferred 10(b)(xxvii) to Form 10-K for 1-8968
Compensation Agreement 1987, 1988, 1989 year ended December 31, 1997
and 1990 Plan Years
(xxxiv) Amendments to Executive Deferred 10(b)(xv) to Form 10-K for year 1-8968
Compensation Agreement between Anadarko ended December 31, 1987
Petroleum Corporation and each Executive
Electing to Participate
(xxxv) Termination of Executive Deferred 10(b)(xxxv) to Form 10-K for 1-8968
Compensation Plan of Anadarko Petroleum year ended December 31, 2000
Corporation, effective July 11, 2000
(xxxvi) Anadarko Retirement Restoration Plan, 10(b)(xix) to Form 10-K for 1-8968
effective January 1, 1995 year ended December 31, 1995
(xxxvii) Anadarko Savings Restoration Plan, 10(b)(xx) to Form 10-K for year 1-8968
effective January 1, 1995 ended December 31, 1995
(xxxviii) Amendment to Amended and Restated Anadarko 10(b)(xxxi) to Form 10-K for 1-8968
Savings Restoration Plan year ended December 31, 1997
(xxxix) Plan Agreement for the Management Life 10(b)(xxi) to Form 10-K for 1-8968
Insurance Plan between Anadarko Petroleum year ended December 31, 1995
Corporation and each Eligible Employee,
effective July 1, 1995
</Table>
<Table>
<Caption>
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
- ------ ------------------------------------------ ------------------------------- ---------
10(b) (xl) Anadarko Petroleum Corporation Estate 10(b)(xxxiv) to Form 10-K for 1-8968
Enhancement Program year ended December 31, 1998
(xli) Estate Enhancement Program Agreement 10(b)(xxxv) to Form 10-K for 1-8968
between Anadarko Petroleum Corporation and year ended December 31, 1998
Eligible Executives
(xlii) Estate Enhancement Program Agreements 10(b)(xxxxii) to Form 10-K 1-8968
effective November 29, 2000 for year ended December 31,
2000
(xliii) Employment Agreement 10(a) to Form 10-Q for quarter 1-8968
ended September 30, 2000
*12 Computation of Ratios of Earnings to Fixed
Charges and Earnings to Combined Fixed
Charges and Preferred Stock Dividends
*21 List of Significant Subsidiaries
*23 Consents of Experts and Counsel Consent of
KPMG LLP
*24 Powers of Attorney
99 Anadarko Petroleum Corporation Proxy Filed on March 22, 2002
Statement, dated March 25, 2002
</Table>
- ---------------
The total amount of securities of the registrant authorized under any instrument
with respect to long-term debt not filed as an exhibit does not exceed 10% of
the total assets of the registrant and its subsidiaries on a consolidated basis.
The registrant agrees, upon request of the Securities and Exchange Commission,
to furnish copies of any or all of such instruments to the Securities and
Exchange Commission.