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, 2002
COMMISSION FILE NO. 1-8968
ANADARKO PETROLEUM CORPORATION
1201 LAKE ROBBINS DRIVE, THE WOODLANDS, TEXAS 77380-1046
(832) 636-1000
INCORPORATED IN THE STATE OF DELAWARE EMPLOYER IDENTIFICATION NO. 76-0146568 |
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 ____.
Indicate by check mark whether registrant is an accelerated filer. Yes X No ____.
The aggregate market value of the voting stock held by non-affiliates of the registrant on June 28, 2002 was $12,128,594,000.
The number of shares outstanding of the Company's common stock as of February 28, 2003 is shown below:
TITLE OF CLASS NUMBER OF SHARES OUTSTANDING
Common Stock, par value $0.10 per share 248,925,066
|
PART OF
FORM 10-K DOCUMENTS INCORPORATED BY REFERENCE
Part II Portions of the Anadarko Petroleum Corporation 2002 Annual
Report to Stockholders.
Part III Portions of the Proxy Statement, dated March 24, 2003, for
the Annual Meeting of Stockholders of Anadarko Petroleum
Corporation to be held April 24, 2003.
|
TABLE OF CONTENTS
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 12
Properties and Activities -- Algeria 14
Properties and Activities -- Other International 17
Drilling Programs 19
Drilling Statistics 19
Productive Wells 20
Marketing and Gathering Properties and Activities 21
Minerals Properties and Activities 21
Segment and Geographic Information 21
Employees 22
Regulatory Matters and Additional Factors Affecting
Business 22
Title to Properties 22
Capital Spending 22
Ratios of Earnings to Fixed Charges and Earnings to
Combined Fixed Charges and Preferred Stock Dividends 22
Item 2. Properties 23
Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of Security Holders 25
Executive Officers of the Registrant 25
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 27
Item 6. Selected Financial Data 27
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 28
Item 7a. Quantitative and Qualitative Disclosures About Market Risk 51
Item 8. Financial Statements and Supplementary Data 53
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 112
PART III
Item 10. Directors and Executive Officers of the Registrant 112
Item 11. Executive Compensation 112
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters 112
Item 13. Certain Relationships and Related Transactions 112
Item 14. Controls and Procedures 112
PART IV
Item 15. Exhibits and Reports on Form 8-K 113
|
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, 2002. 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
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. The Land Grant is an 8 million acre
strip running through portions of Colorado, Wyoming and Utah where the Company
owns most of its fee mineral rights.
In July 2000, the Company merged with Union Pacific Resources Group Inc.,
subsequently renamed Anadarko Holding Company (Anadarko Holding). The merger was
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 the merger and of the combined Company from that
date forward.
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.
Available Information The Company files Annual Reports on Form 10-K, Quarterly
Reports on Form 10-Q, Current Reports on Form 8-K, registration statements and
other items with the Securities and Exchange Commission (SEC). Anadarko provides
access free of charge to all of these SEC filings, as soon as reasonably
practicable after filing, on its Internet site located at www.anadarko.com. The
Company will also make available to any stockholder, without charge, copies of
its Annual Report on Form 10-K as filed with the SEC. For copies of this, or any
other filings, please contact: Anadarko Petroleum Corporation, Public Affairs
Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-3498.
In addition, the public may read and copy any materials Anadarko files with
the SEC at the SEC's Public Reference Room at 450 Fifth Street, NW, Washington,
DC 20549. The public may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an
Internet site (www.sec.gov) that contains reports, proxy and information
statements and other information regarding issuers, like Anadarko, that file
electronically with the SEC.
OIL AND GAS PROPERTIES AND ACTIVITIES
PROVED RESERVES AND FUTURE NET CASH FLOWS
As of December 31, 2002, Anadarko had proved reserves of 1.1 billion
barrels of crude oil, condensate and NGLs and 7.2 trillion cubic feet (Tcf) of
natural gas. Combined, these proved reserves are equivalent to 2.3 billion
barrels of oil or 14.0 Tcf of gas. The Company's reserves have grown
significantly over the past three years due to: the Anadarko Holding merger
transaction in 2000; the acquisitions of Berkley Petroleum Corp. (Berkley) and
Gulfstream Resources Canada Limited (Gulfstream) in 2001 and Howell Corporation
(Howell) in 2002; substantial natural gas reserves discovered in the Gulf of
Mexico, Canada and onshore in the U.S.; crude oil reserves added in Algeria and
Alaska; and, through other acquisitions of producing properties.
As of December 31, 2002, Anadarko had proved developed reserves of 5.3 Tcf
of natural gas and 686 million barrels (MMBbls) of crude oil, condensate and
NGLs. Proved developed reserves comprise 67% of total proved reserves.
The Company's estimates of proved reserves and proved developed reserves at
December 31, 2002, 2001 and 2000 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 2002
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.
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.
2002 2001 2000
---- ---- ----
UNITED STATES
Natural gas (Bcf) 507 573 338
Oil and condensate (MMBbls) 31 34 15
Natural gas liquids (MMBbls) 14 14 12
Total (MMBOE) 130 144 83
CANADA
Natural gas (Bcf) 135 121 46
Oil and condensate (MMBbls) 12 13 4
Natural gas liquids (MMBbls) 1 1 --
Total (MMBOE) 35 34 12
ALGERIA
Oil and condensate (MMBbls) 24 8 10
Total (MMBOE) 24 8 10
OTHER INTERNATIONAL
Natural gas (Bcf) -- 1 1
Oil and condensate (MMBbls) 8 13 7
Total (MMBOE) 8 13 7
TOTAL
Natural gas (Bcf) 642 695 385
Oil and condensate (MMBbls) 75 68 36
Natural gas liquids (MMBbls) 15 15 12
Total (MMBOE) 197 199 112
|
The following table shows the Company's annual average 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. Production costs are costs incurred to operate and maintain the Company's wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, property taxes, production and severance taxes and overhead charges. Certain amounts for prior years have been reclassified to conform to the current presentation. 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 12 of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
2002 2001 2000
------ ------ ------
UNITED STATES
Sales price
Natural gas (per Mcf) $ 2.84 $ 4.23 $ 4.22
Oil and condensate (per barrel) 23.07 23.08 28.59
Natural gas liquids (per barrel) 14.98 16.44 21.65
Production cost (per BOE) $ 4.66 $ 4.66 $ 5.05
CANADA
Sales price
Natural gas (per Mcf) $ 2.93 $ 4.38 $ 4.09
Oil and condensate (per barrel) 19.31 18.18 27.33
Natural gas liquids (per barrel) 12.11 18.32 --
Production cost (per BOE) $ 6.40 $ 5.97 $ 6.80
ALGERIA
Sales price
Oil and condensate (per barrel) $24.38 $23.97 $28.73
Production cost (per BOE) $ 1.78 $ 2.33 $ 2.61
OTHER INTERNATIONAL
Sales price
Natural gas (per Mcf) $ -- $ 1.22 $ 1.08
Oil and condensate (per barrel) 19.92 14.35 18.35
Production cost (per BOE) $ 8.48 $ 5.71 $ 8.24
TOTAL
Sales price
Natural gas (per Mcf) $ 2.86 $ 4.25 $ 4.19
Oil and condensate (per barrel) 22.55 20.56 26.42
Natural gas liquids (per barrel) 14.80 16.55 21.70
Production cost (per BOE) $ 4.79 $ 4.85 $ 5.27
|
PROPERTIES AND ACTIVITIES -- UNITED STATES
Reserves in the United States comprised 66% of Anadarko's total proved reserves at year-end 2002 compared to 61% in 2001 and 64% in 2000. During 2002, drilling results included 392 gas wells, 98 oil wells and 24 dry holes. 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 54% 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 2002, average production from the
Company's onshore properties was 1,165 million cubic feet per day (MMcf/d) of
gas and 91 thousand barrels per day (MBbls/d) of crude oil, condensate and NGLs,
or 53% of the Company's total production volumes. Anadarko has 2,642,000 gross
(1,904,000 net) undeveloped lease acres, 2,900,000 gross (1,959,000 net)
developed lease acres and 9,538,000 gross (8,488,000 net) fee acres onshore in
the Lower 48 states.
[ONSHORE PROPERTIES MAP]
NET NET NET NET
UNDEVELOPED DEVELOPED FEE PRODUCING
ACRES ACRES ACRES WELLS
----------- ----------- --------- ---------
ONSHORE:
United States
Alabama 1,241 2,676 11,473 20
Alaska* 1,161,766 5,851 7,978 7
Arkansas 835 1,100 333,715 1
California* 11,764 469 3,763 1
Colorado 9,773 20,507 2,888,248 210
Florida -- -- 5,342 --
Georgia -- -- 2,838 --
Idaho -- -- 711 --
Illinois -- -- 7,738 --
Indiana 913 -- 9,913 --
Iowa -- -- 211 --
Kansas* 260,299 365,658 35,524 1,723
Louisiana* 146,609 131,207 13,736 181
Michigan 21 -- -- --
Mississippi 11,051 1,543 63,880 7
Missouri -- -- 11,321 --
Montana 137,462 1,538 357 81
Nebraska 4,643 926 28,118 1
New Mexico 5,729 23,878 418 151
Nevada -- -- 440 --
North Dakota 201 1,791 -- 5
Oklahoma* 75,851 194,144 35,366 1,375
Oregon -- -- 741 --
South Carolina -- -- 2,734 --
South Dakota -- -- 3,161 --
Tennessee -- -- 902 --
Texas* 715,618 1,109,775 171,322 6,445
Utah* 7,716 23,138 690,155 155
Virginia -- -- 14 --
Washington -- -- 2,521 --
West Virginia 330 -- -- --
Wyoming* 514,272 80,555 4,163,092 2,065
OFFICE LOCATIONS:
United States
Amarillo,Texas
Anchorage, Alaska
Midland, Texas
The Woodlands, Texas
|
* Drilling activities were conducted in these areas in 2002.
EAST TEXAS AND LOUISIANA
Bossier Play Since operations began in 1996, the Company has discovered seven
significant fields, achieved a development success rate of nearly 100% and
expanded the Bossier play from east Texas into north Louisiana. The Bossier play
consists of multiple fields and multiple pay zones. The majority of the
Company's production is from the Bossier Sand interval.
During 2002, Anadarko continued drilling in the Bossier play and had a
total of 14 rigs drilling (eight in east Texas and six in north Louisiana) at
year-end. The Company drilled 83 wells in 2002 with a success rate of 93%.
Bossier volumes for 2002 totaled 96 Bcf (net), or roughly 15% of the Company's
total gas production, making it Anadarko's largest onshore gas area. Anadarko
had a total of 489,000 net acres in the area at year-end 2002. During 2003, the
Company expects to operate about 12 rigs (seven in east Texas and five in north
Louisiana) to drill 81 wells, including at least four exploration wells, in the
Bossier play. In 2003, total spending in the Bossier play is expected to be $251
million, which includes $12 million for exploration.
In the east Texas Bossier, Anadarko has drilled 473 wells and had a total
of 359,000 net acres as of the end of 2002. During 2002, the Company's net gas
production averaged 192 MMcf/d from the Bossier play of east Texas. Despite the
significant reduction in drilling during 2002 -- the Company drilled 56 wells
compared to over 140 wells in 2001 -- production declines were modest due to the
Bossier field's production characteristic as a long-life asset. Exploration
continued at a steady pace during 2002 to expand the play deeper into the basin
and identify new field reserves. During 2002, a discovery was made with the
Gregory A-1 well (100% working interest (WI)). One successful delineation well
had been drilled as of the end of 2002 and delineation drilling continues. The
Company also continued to expand the Dowdy Ranch field during 2002, drilling
four successful delineation wells.
In the north Louisiana Bossier, the Vernon field was producing 70 MMcf/d of
gas (net) from 78 wells at the end of 2002. Anadarko has extended the Vernon
field significantly over the past three years through successful drilling. A
total of 27 wells were drilled in the Vernon/Ansley area in 2002, with a 96%
success rate. A 3-D seismic survey is being acquired in order to help identify
exploration prospects. At year-end 2002, Anadarko's position in the play totaled
130,000 net acres.
Carthage Anadarko is conducting a successful development program in the Carthage area. The Company drilled eight Cotton Valley infill wells during 2002. Anadarko has additional infill locations to drill and is studying the potential for increased well density in the area. The Company had five rigs performing workovers and re-completions throughout the Carthage area at the end of 2002. Anadarko's net production from the Carthage area averaged 105 MMcf/d of gas and 2 MBbls/d of liquids during 2002. The Company has budgeted $22 million and plans to drill 20 wells in the Carthage area in 2003.
South Louisiana At year-end 2002, net volumes averaged 37 MMcf/d of gas and 10 MBbls/d of oil and NGLs. Activity in the Kent Bayou field during 2002 consisted primarily of re-completing existing wells. During 2002, the Company also sold several non-core properties in other areas of south Louisiana.
CENTRAL TEXAS/GULF COAST Anadarko's horizontal drilling program continues to be
the focus in central Texas. During 2002, Anadarko drilled 52 wells, with a
success rate of 94%, to exploit the multiple pay zones in the Giddings, Mossy
Grove and Brookeland fields in central Texas. Anadarko also operates wells in
the Masters Creek field located in Louisiana. The Company had a working interest
ownership in 1,000,000 net acres in this area at the end of 2002, which was
largely held by production. During 2002, net volumes averaged approximately 158
MMcf/d of gas, 16 MBbls/d of oil and 2 MBbls/d of NGLs. In 2002, Anadarko
operated over 1,500 wells in this area. In 2003, Anadarko expects to drill 62
wells, including two exploratory wells, as part of a six-rig program. The
Company has budgeted approximately $134 million for these projects in 2003.
The Company continued its cost-efficient horizontal re-entry program in the
Giddings field. The cost to re-enter a well is about 40% less than the cost of a
new well. During 2002, 33 wells were re-entered and completed. Anadarko plans to
expand this program in 2003 and intends to re-enter 45 wells. Additionally,
Anadarko continued its successful water-fracturing program. Approximately 90
wells were stimulated in 2002 and over 100 wells are expected to be stimulated
in 2003.
During 2002, the Company continued development and exploration in the Mossy
Grove field. The 2003 drilling program will continue to evaluate the potential
of this multi-pay area.
Anadarko's development program included the drilling and completion of six
wells in 2002 in the Brookeland field, where the Company has a working interest
ownership in nearly 170,000 net acres. In 2003, the Company plans to continue
development and looks to extend this field through increased drilling activity
and water-fracture stimulation as well as the evaluation of a re-entry program
similar to the Giddings field.
PERMIAN BASIN During 2002, Anadarko drilled 71 wells with a 99% success rate in
the Permian basin. Two exploration wells were drilled -- one was a discovery
that tested at 5 MMcf/d of gas and the other is being tested. Evaluation
continues and additional exploration drilling is planned for 2003. In addition,
the Company performed 237 workovers and re-completions and completed
installation of a carbon dioxide (CO(2)) flood. Net production for 2002 averaged
91 MMcf/d of gas, 11 MBbls/d of oil and 2 MBbls/d of NGLs. Anadarko has
interests in 419,000 gross (304,000 net) acres in the Permian basin and operates
approximately 5,000 wells. During 2002, Anadarko made a strategic decision to
exit some 300 non-core properties, covering 18,000 net acres, in southeast New
Mexico with 2002 annual net production of about 700 thousand barrels of oil
equivalent (MBOE). The properties were sold for $41 million in January 2003.
In the Ozona field, located in Texas, development continued with the
Company drilling and completing 49 wells and re-completing 89 wells during 2002.
In 2002, net production averaged 64 MMcf/d of gas. Anadarko operates about 1,900
wells in the Ozona field and plans to drill 52 new wells and re-complete 75
wells in 2003.
During 2002, the Company drilled 11 infill wells in the TXL North, TXL
South and Goldsmith Cummins Deep waterflood units. Net production from these
units averaged 3 MBbls/d of oil in 2002. Anadarko plans to drill an additional
74 infill wells in the area in 2003.
MID-CONTINENT
Hugoton Embayment Anadarko's drilling 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 978,000 gross (880,000 net) acres in this area and operates
about 2,300 wells. The deep drilling program in Kansas and the Oklahoma
panhandle utilizes 3-D seismic technology to locate oil and gas bearing zones.
During 2002, the Beaver River field was a new discovery in Oklahoma. Success was
also achieved drilling in the Ryus and Many Creeks fields in Kansas.
The Company's net production from the Hugoton Embayment area during 2002
averaged 170 MMcf/d of gas and 17 MBbls/d of oil, condensate and NGLs. In 2002,
the Company drilled 32 deep wells with a 66% success rate. Anadarko also
re-completed 16 wells and carried out workover operations on 126 wells in the
area. In 2003, the Company has budgeted $22 million in the area and plans to
drill about 26 wells.
Texas Panhandle During 2002, the Company produced an average of 24 MMcf/d of gas (net) from 218 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 million cubic feet (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 2002, net production from central Oklahoma was 25 MMcf/d of gas and 3 MBbls/d of oil. While continuing to develop the deeper gas producing zones, the majority of Anadarko's focus in 2002 has been developing a shallower oil play located in the Rush Creek field. In 2002, Anadarko drilled and completed 11 wells in the field resulting in a net production increase of 1 thousand barrels of oil equivalent per day (MBOE/d). During 2003, the Company has budgeted $15 million to drill about 20 wells in central Oklahoma. Anadarko plans to continue development in the Rush Creek and traditional deep gas areas.
WESTERN STATES
Overview Anadarko continues to increase its activity level and production in
the western states area, with significant exploration and development activity
in conventional and coalbed methane (CBM) plays. The western states area
primarily includes the Company's oil and gas properties in the Land Grant area
of Wyoming, Colorado and Utah. Economics on the Land Grant acreage are greatly
enhanced by Anadarko's fee mineral ownership position. For example, in a typical
non-operated well that is outside of the Land Grant, Anadarko may have a 25%
working interest with a 20% net revenue interest. However, on the Land Grant,
because of the Company's fee mineral ownership, Anadarko may have a 25% working
interest with a 33.75% net revenue interest. Anadarko's operations on the Land
Grant are concentrated in the Green River basin and the Overthrust area.
The Company currently has approximately 8,878,000 gross (8,313,000 net)
acres, principally attributable to its Land Grant ownership. Anadarko and its
partners drilled 184 wells in the area in 2002 with an overall success rate of
98%. Anadarko's 2002 net production from the western states area averaged 307
MMcf/d of gas, 9 MBbls/d of oil and 14 MBbls/d of NGLs. Anadarko plans to invest
about $237 million in the western states area for exploration and development in
2003. The Company's 2003 plans include drilling 277 development and 2
exploratory wells in Wyoming, Colorado and Utah.
Acquisitions In December 2002, Anadarko acquired Howell for approximately $258 million, including the bank debt of Howell, which was $53 million. The Company booked 64 MMBOE of proved reserves, primarily in the Salt Creek and Elk Basin fields, related to this acquisition. Howell's net production of about 12 MBOE/d is primarily from the western states area. In a separate transaction, Anadarko acquired the rights to purchase significant quantities of CO(2) and the exclusive rights to market and transport the CO(2) into the Powder River basin for $3 million and certain future consideration based on the performance of the pipeline. The Company expects to invest an additional $200 million over the next four years for the development and installation of a CO(2) enhanced oil recovery project. Anadarko plans to build a 125 mile pipeline that would deliver CO(2) to the enhanced oil recovery project in the Salt Creek field and potentially could serve other enhanced oil recovery projects in Wyoming as well. These projects are expected to result in an increase in net production from the Salt Creek field from 5 MBOE/d to 35 MBOE/d by the end of 2006.
Wyoming During 2002, Anadarko's net production from its properties located in
Wyoming averaged 221 MMcf/d of gas, 5 MBbls/d of oil and 11 MBbls/d of NGLs. In
the Green River basin of Wyoming, Anadarko focused on conventional drilling
projects in the Wamsutter and Brady areas. In 2002, the Company drilled or
participated in 123 wells in the Green River basin, with an overall success rate
of 98%. In 2003, the Company plans to spend $65 million to drill 93 additional
wells in the area. During 2002, Anadarko drilled 17 operated development wells
(88% average WI) and participated in 93 outside-operated wells (23% average WI)
in the Wamsutter area. In 2003, the Company plans to double the number of
operated wells drilled.
During 2002, the Company acquired 585 miles of new proprietary 2-D seismic
data in the Hanna basin and the Overthrust Belt. Anadarko continues to process
and interpret this seismic data to identify new plays and prospects in the
under-explored basins of southern Wyoming. In 2003, the Company plans to drill
two exploration wells based on this new seismic data. During 2002, the Bureau of
Land Management approved the Fort Steele Federal Development Contract in the
Hanna basin area. The Company holds a working interest ownership in 760,000
gross and net acres in this area. Anadarko drilled or participated in five
exploratory wells in the western states area in 2002 -- three are being
evaluated and two were unsuccessful.
Coalbed Methane Production from the Company's CBM properties continued to
increase during 2002. At year-end 2002, net production averaged 61 MMcf/d of gas
compared to 34 MMcf/d of gas in 2001. CBM gas production is expected to steadily
increase over the next several years. In 2003, the Company plans to continue to
explore for and develop CBM reserves and has budgeted $38 million to drill 130
wells.
The Company's Big George project in the Powder River basin of Wyoming
started in late 2001. At year-end 2002, the project was producing 9 MMcf/d of
gas (net) from 74 wells. During 2002, the Company drilled three wells in the
Helper and Drunkard's Wash fields in Utah, with a success rate of 100%.
The Company continues to evaluate new CBM exploration opportunities on the
Land Grant. During 2002, an Anadarko-operated pilot program was initiated at
Copper Ridge in Wyoming (50% WI) to test the productivity of the Almond coal
formation at a depth of about 3,200 feet. Four pilot wells were drilled and were
producing 200 Mcf per day of gas at year-end 2002. Additionally, along the Land
Grant, Anadarko entered into a 50/50 joint venture to develop 133,300 acres for
CBM in the Atlantic Rim project area. Anadarko will operate 36 wells with first
production expected in early 2003 and plans to drill 32 additional wells
throughout the year within the joint venture.
ALASKA
OVERVIEW Anadarko's activity in Alaska is concentrated primarily on the North Slope. The Company had interests in 3,144,000 gross (1,162,000 net) undeveloped lease acres, 25,000 gross (6,000 net) developed lease acres and 16,000 gross (8,000 net) fee acres in Alaska at year-end 2002. In addition, the Company is finalizing agreements on leases covering 181,000 gross (60,000 net) 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 additional 1,941,000 gross (647,000 net) acres. During 2002, Anadarko announced that it was the apparent high bidder on a total of 34 tracts in the National Petroleum Reserve-Alaska (NPR-A) Oil and Gas Lease Sale 2002. The 34 tracts cover more than 282,000 gross (96,000 net) acres and are located primarily west of the Company's Moose's Tooth discovery. Including the acres from the 2002 lease sale, Anadarko's leasehold in NPR-A totals about 910,000 gross (289,000 net) acres. In total, Anadarko had access to approximately 5,380,000 gross (1,923,000 net) acres in Alaska through current and pending leases or options.
NORTH SLOPE
Development The Alpine field (22% WI) on Alaska's North Slope produced an
average of 96 MBbls/d of oil (gross) in 2002. A facility expansion to increase
produced water handling in the field and eliminate minor oil train bottlenecks,
scheduled to be completed in 2004, should increase production capacity to 110
MBbls/d. As of year-end 2002, 33 production wells and 32 injection or service
wells had been completed. When completed, the entire Alpine development program
is expected to have 94 horizontal wells from two drill sites.
During 2002 at Colville Delta 2, the drill site used to develop the western
part of the field, development drilling continued with 19 wells (8 production
and 11 injection wells) drilled and completed. The Nanuq and Fiord satellites
(22% WI), previous discoveries near Alpine, are expected to be developed and
produced through the Alpine facility beginning in 2006, filling in the natural
production decline of Alpine.
Exploration During the 2001-2002 winter exploration season, the Company
participated in the drilling of six wells. Four wells were located in the NPR-A
and two in the Central Arctic. The Lookout #2 well successfully appraised the
Lookout discovery. The well encountered the Alpine equivalent reservoir and
tested at 4 MBbls/d of oil and 8 MMcf/d of gas after fracture stimulation. The
Altamura #1, the Company's first operated well on the North Slope, encountered
pay with low permeability and was temporarily abandoned. Results from the other
wells have not yet been released. The Spark, Moose's Tooth and Rendezvous
accumulations that have been identified within the vicinity require further
delineation drilling and testing. An Environmental Impact Study has been
initiated in cooperation with the Bureau of Land Management as the first step
towards approval of development of reserves at the Spark, Lookout, Nanuq, Fiord
and West Alpine fields.
During 2002, the Company participated in the acquisition of proprietary 3-D
seismic in the NPR-A preparing for lease sales and 2003 drilling activity. The
Company also acquired 2-D seismic and proprietary 3-D seismic in the Foothills.
During the 2002-2003 winter drilling season, Anadarko expects to
participate in two exploration projects, the Puviaq prospect (40% WI), located
near Teshekpuk Lake in the NPR-A and the Oberon prospect, an Alpine satellite
opportunity. Anadarko is also planning to acquire proprietary 2-D seismic data
in the Foothills and participate in the acquisition of proprietary 3-D seismic
around the Alpine field. The Company will operate a drilling program to study
the feasibility of producing methane hydrates from the arctic tundra. This
program will utilize Anadarko's self-contained, elevated drilling platform
called the Arctic Platform Drilling System, which is designed to be lightweight,
modular and mobile. This system is intended to be utilized in logistically
challenging areas with minimal surface impact, potentially extending traditional
drilling seasons.
COOK INLET During 2002, the Company sold all of its Cook Inlet holdings including 41,000 net acres and net proved reserves of less than 1 MMBOE with no production.
GULF OF MEXICO
OVERVIEW At year-end 2002, about 8% of the Company's proved reserves were located offshore in the Gulf of Mexico. Net production volumes in 2002 from these properties averaged 230 MMcf/d of gas and 16 MBbls/d of oil, condensate and NGLs. At year-end 2002, Anadarko owned an average 70% interest in 371 blocks representing 441,000 gross (204,000 net) acres in developed properties and 1,450,000 gross (1,126,000 net) acres in undeveloped properties in the Gulf of Mexico. Anadarko also holds options to earn working interests covering an additional 106 blocks. During 2002, Anadarko participated in 23 wells in the Gulf of Mexico: 9 shelf conventional, 7 sub-salt and 7 deepwater wells. Drilling results in the Gulf of Mexico included 9 gas wells, 9 oil wells and 5 dry holes for a success rate of 78%. In the Gulf of Mexico, Anadarko has budgeted about $460 million for capital spending in 2003, which includes drilling about 40 wells.
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-processing of seismic and re-mapping have generated numerous
prospects, adding to the Company's large inventory of projects identified from
extensive field studies. During 2002, nine successful wells were drilled for a
100% success rate. Anadarko has interests in a total of 93 blocks on the shelf.
Activity in 2002 was highlighted by the Company's continued success at
South Marsh Island (SMI) 280/281 (30-50% WI). During 2002, the "H" and "I"
platforms at SMI 280/281 were completed. Additional drilling and workovers are
planned for 2003, including several deep tests. In 2003, the Company is planning
to drill 18 development and three exploratory wells near its older existing
fields.
SUB-SALT During 2002, Anadarko continued to delineate the Tarantula (100% WI)
sub-salt discovery made during 2001, which is located on South Timbalier 308.
The #2ST#1 confirmation well was drilled and encountered 153 feet of net pay in
five zones. A third well was drilled in late 2002 to further delineate the
discovery and encountered 44 feet of net pay in the primary zone. A fourth well
drilled in 2003 encountered over 100 feet of pay in various intervals. The
Company has authorized construction of an $86 million production platform during
2003 with a capacity of 100 MMcf/d of gas and 30 MBbls/d of oil. Production is
expected to commence in the fourth quarter of 2004.
During 2002, production continued from the Hickory (50% WI) and Tanzanite
(100% WI) sub-salt fields discovered in 1998 off the coast of Louisiana. The
Hickory A-5 well, drilled in 2002, encountered 105 feet of net pay in four sands
and has been completed in a deeper pay interval. This additional development
well should increase production rates of the field and more effectively drain
the reservoir.
Anadarko has commenced installation of equipment for the Pardner (100% WI)
sub-sea tieback. First production, from this 2001 discovery, is expected during
the second quarter of 2003 at a rate of 3 MBbls/d of oil.
Anadarko has interests in a total of 114 blocks in its sub-salt program,
with 38 prospects identified. An additional 11 blocks could be earned within its
option program. Three exploratory wells and six development wells are planned in
the sub-salt for 2003.
DEEPWATER Marco Polo (100% WI), Anadarko's first deepwater development project,
is located on Green Canyon Block 608 in 4,300 feet of water approximately 180
miles offshore Louisiana in the Gulf of Mexico. Anadarko made the Marco Polo
discovery in 2000. During 2002, four development wells were drilled and had
better than expected results -- thicker pay and higher quality sands. Anadarko
drilled two additional development wells at Marco Polo in early 2003, both of
which were successful.
In April 2002, the Company signed an agreement under which a production
platform for its Marco Polo discovery, as well as other nearby fields, will be
installed. The other party to the agreement will construct and own the platform
and production facilities. Production capacity of the facility will be 120
MBbls/d of oil and 300 MMcf/d of gas, which is greater than expected production
from Marco Polo. Anadarko will have firm capacity of 50 MBbls/d of oil and 150
MMcf/d of gas. The platform is currently under construction and installation is
planned for late 2003. When completed, Anadarko will be the operator of the
platform. Production is expected to commence in the first quarter of 2004.
During 2002, Anadarko and its partners announced a successful deepwater
sub-salt appraisal well at K2 on Green Canyon Block 562 (52% WI) in the Gulf of
Mexico, approximately six miles northwest of Marco Polo. The K2 #2 well
encountered a total of 339 feet of oil pay in three sands in an untested fault
block and reached target depth of 25,700 feet. The well extends the limits of
the discovery on the K2 structure. Additional appraisal operations will continue
in 2003.
(OFFSHORE MAP)
NET NET NET
UNDEVELOPED DEVELOPED PRODUCING
ACRES ACRES WELLS
----------- --------- ---------
OFFSHORE:
United States
California.......... 2,785 -- --
Florida............. 189,590 -- --
Louisiana*.......... 451,502 172,237 156
Mississippi......... 169,909 3,996 --
Texas*.............. 315,336 28,230 43
|
* Drilling activities were conducted in these areas in 2002.
Anadarko has submitted plans of exploration to the Minerals Management
Service on four deepwater prospects located in the eastern portion of the Gulf
of Mexico, of which three are within and one is partially adjacent to the Lease
Sale 181 area (see Lease Sales). Three of the permits have been approved and
drilling began in early 2003.
Anadarko holds a total of 164 lease blocks in its deepwater program and has
identified 29 prospects. An additional 95 blocks could be earned within its
option program. Five deepwater exploratory wells are planned for 2003.
South Auger Participation Agreement Anadarko has a Participation Agreement with BP to explore 95 deepwater blocks 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.
LEASE SALES In January 2002, Anadarko acquired 26 tracts (100% WI) in the Eastern Gulf of Mexico Lease Sale 181. The Company's total investment was $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 Lease Sale 181 have not been available for exploration since 1988, long before major advancements occurred in seismic imaging and deepwater drilling and development technology. The Company is considering taking on partners to recover lease costs and reduce risk. Anadarko also acquired nine tracts (100% WI) covering about 42,000 acres at Gulf of Mexico Lease Sales 182 and 184 held during 2002. The Company's total investment was about $3 million.
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 11 plants in the gulf coast area. Anadarko also processes gas and has interests in three Company-operated plants 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 has operations in Alberta, British Columbia, Saskatchewan and
in the Northwest Territories. The Company has proved reserves in Canada of 288
MMBOE, which includes 1.3 Tcf of gas and 64 MMBbls of crude oil, condensate and
NGLs. In 2002, net production from the Company's properties in Canada averaged
370 MMcf/d of gas and 35 MBbls/d of crude oil, condensate and NGLs, or 18% of
the Company's total production volumes. During 2002, Anadarko participated in a
total of 391 wells with a 97% success rate, including 294 gas wells, 84 oil
wells and 13 dry holes. Anadarko has 9,357,000 gross (3,343,000 net) undeveloped
lease acres, 1,811,000 gross (1,024,000 net) developed lease acres and 605,000
gross (605,000 net) fee acres in Canada.
The Company significantly increased its exploration activity in Canada
during 2002, participating in 46 wells with an 83% success rate. As one of the
most active drillers in Canada, Anadarko reached a peak of 26 operated rigs with
10 rigs drilling exploratory wells during 2002. The Company's 2003 capital
budget of $360 million for Canada includes approximately $250 million for
development drilling and infrastructure and $110 million for exploration,
including approximately 43 exploration wells. The accompanying map illustrates
the Company's developed and undeveloped lease and fee acreage, number of
productive wells and other data relevant to its properties in Canada.
(CANADA MAP)
NET NET NET NET
UNDEVELOPED DEVELOPED FEE PRODUCING
ACRES ACRES ACRES WELLS
----------- --------- ------- ---------
CANADA:
Alberta*.............................. 979,887 554,116 516,257 1,096
British Columbia*..................... 869,250 193,665 -- 228
Northwest Territories*................ 1,119,283 1,863 -- 1
Saskatchewan*......................... 142,132 274,260 88,683 2,133
Scotian Shelf......................... 231,975 -- -- --
OFFICE LOCATIONS:
Canada
Calgary, Alberta
Fort St. John, British Columbia
Medicine Hat, Alberta
Peace River, Alberta
|
* Drilling activities were conducted in these areas in 2001.
ALBERTA During 2002, production in the Saddle Hills area of northern Alberta
reached a record 64 MMcf/d of gas after a natural gas pipeline was completed to
a processing plant and wells were tied in. A total of 12 net wells were
completed during 2002. In addition, Anadarko increased its position in the area
by over 37,000 net acres during the year and acquired 86 square miles of 3-D
seismic.
In the Alberta Foothills, a horizontal gas well was completed and tested at
a rate of about 6 MMcf/d of gas. Anadarko participated in a second well in the
Alberta Foothills that tested at about 7 MMcf/d of gas. In the Wild River area
of west central Alberta, 21 wells were completed during 2002. Net production
from the Wild River area was 34 MMcf/d of gas and 400 barrels per day of NGLs at
the end of 2002. Regulatory approval for commingling production zones was
obtained in 2002, allowing Anadarko to immediately complete up to six zones per
well. In the Dawson oil field in northwest Alberta, 20 wells were completed in
2002.
During 2002, Anadarko sold its heavy oil assets in eastern Alberta in
several separate transactions for a total of about $160 million. The sale
included 28 MMBOE of net proved reserves and production of approximately 21
MBOE/d.
BRITISH COLUMBIA During 2002, in northeast British Columbia, two operated
proprietary 3-D seismic programs were conducted over the Jedney and Adsett
areas. The Company continued to experience success throughout the year in the
Slave Point play. Several exploratory wells were completed and brought on
production at an average rate of approximately 5 MMcf/d of gas.
In the British Columbia Foothills, the Monkman b-79-J (30% WI) discovery
was tied in and came on production at an initial rate of 15 MMcf/d of gas. An
offset well began drilling in the fourth quarter of 2002. In the evolving West
Blueberry tight gas play, Anadarko brought four new wells on-line at an average
rate of 5 MMcf/d of gas.
SASKATCHEWAN During 2002, the Company drilled and completed 203 shallow gas wells with an overall success rate of 100%. In the Hatton area, the Company drilled 168 operated wells and participated in another 28 non-operated wells. Net production from the Hatton area averaged 73 MMcf/d of gas in 2002.
NORTHWEST TERRITORIES Anadarko completed two proprietary 3-D seismic programs
and a proprietary 2-D seismic program in the southern Northwest Territories near
Fort Liard in 2002. The Netla A-68 well drilled in 2002 was a discovery.
Anadarko also completed a 122 mile proprietary 2-D seismic program over
Block 407 (100% WI) and participated in three additional proprietary seismic
programs in the Mackenzie Delta.
PROPERTIES AND ACTIVITIES -- ALGERIA
OVERVIEW Anadarko is actively developing and producing oil fields discovered by
the Company in Algeria's Sahara Desert. Since 1989, Anadarko has participated in
99 productive wells (13 exploration and 86 delineation/ development) located in
13 fields in Algeria. Eight of the fields are actively being developed and are
on production. Final approval to develop four of the fields has been requested
and is pending government approval. One field was recently discovered and a
Commerciality Report is being prepared. Anadarko has developed a good working
relationship with Sonatrach, the national oil and gas enterprise of Algeria, its
partner in all development projects within Algeria. Sonatrach has owned shares
of the Company's common stock since 1986 and at year-end 2002 was the registered
owner of 4.9% of Anadarko's outstanding common stock.
The Company has proved reserves in Algeria of 372 MMBbls of crude oil as of
year-end 2002. In 2002, net sales volumes from the Company's properties in
Algeria totaled 24 MMBbls of crude oil, or 12% of the Company's total sales
volumes.
In 2002, Anadarko participated in 34 wells with a success rate of 88%.
Anadarko plans to invest about $98 million in Algeria in 2003. At the end of
2002, the Company had 3,994,000 gross (1,221,000 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.
(ALGERIAN PROPERTIES MAP)
CONTRACTS/PARTNERS
Blocks 404, 208 and 211 Production Sharing Agreement Anadarko's interest in the
original production sharing agreement (PSA) is 50% before participation at the
exploitation stage by Sonatrach. The Company has two joint venture partners,
each with a 25% interest in the Algerian venture, also prior to participation by
Sonatrach. Under the terms of the PSA, oil reserves that are discovered,
developed and produced are shared by Sonatrach, Anadarko and its two joint
venture partners. Anadarko and its joint venture 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 2002, Anadarko and
its joint venture partners had recovered about 93% of Sonatrach's portion of
exploration costs through an increased share of production (cost recovery oil)
with the majority of the remaining 7% expected to be recovered during 2003.
Sonatrach is responsible for 51% of development and production costs. Sonatrach
and Anadarko formed a non-profit company, Groupement Berkine, to carry out the
majority of 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. The exploration phase of the original PSA
ended in 1998. 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.
See Exploration.
Block 406b Production Sharing Agreement The Company has a separate exploration license for Block 406b in which Anadarko had a 100% interest. During 2002, the Company finalized an agreement to farm-out a 40% working interest in this block.
Block 403c/e Production Sharing Agreement In 2002, Anadarko was awarded exploration rights over Block 403c/e. Anadarko will hold a 67% interest in the exploration phase of this venture.
DEVELOPMENT
Block 404 -- Hassi Berkine South Central Production Facility Production from
the Hassi Berkine South (HBNS) field averaged 125 MBbls/d of oil (gross) in 2002
compared to 77 MBbls/d of oil (gross) in 2001. The fourth processing unit was
completed in April 2002, bringing the total HBNS facility capacity to 300
MBbls/d of oil. During 2002, three of the satellite fields - Hassi Berkine South
East (HBNSE), Berkine North East (BKNE) and Rhourde Berkine (RBK) - commenced
production and averaged 22 MBbls/d of oil (gross). During 2002, 17 wells were
drilled in the HBNS and satellite fields, resulting in 16 productive wells and
one unsuccessful well.
Groupement Berkine is also developing the Hassi Berkine (HBN) field that is
located just to the north of the HBNS field. This producing field extends into
Block 403, which is under a different association with Sonatrach. Unitization of
the field was accomplished to facilitate development activities. A crude oil
production train with the capacity to process 75 MBbls/d of oil has been
installed as part of the HBNS facility. Production from the HBN field averaged
67 MBbls/d of oil (gross) in 2002. During 2002, three productive wells were
drilled in the HBN field with a 100% success rate.
Block 404 -- Ourhoud Central Production Facility Anadarko is also actively involved in developing the Ourhoud field, the second largest oil field in Algeria. Located in the southern portion of Block 404, the Ourhoud field extends into Block 406a and Block 405 and is unitized with the companies with interests in those blocks. The field is operated by the Ourhoud Organization, which represents the interests of the three associations involved in this development. Production from the field commenced in November 2002 two months ahead of schedule and reached rates of 71 MBbls/d of oil (gross) by year-end 2002. Ourhoud is expected to be fully operational during the first half of 2003 with facility capacity reaching 230 MBbls/d of oil. During 2002, a total of six productive wells were drilled in the Ourhoud field.
Block 208 Anadarko also has several fields farther 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). During 2002, Sonatrach approved the Commerciality Reports for these fields and the Exploitation License Applications were submitted to the Ministry of Energy and Mines for approval. Once the Exploitation Licenses are approved, Anadarko will proceed with design and construction of a third Central Production Facility. During 2002, a total of five wells were drilled in the Block 208 fields, resulting in four productive wells and one unsuccessful well.
EXPLORATION The 1989 PSA, as amended in 2001, allows Anadarko and its joint
venture partners to resume exploration on Blocks 404, 208 and 211, outside of
the exploitation license boundaries encompassing the previous discoveries. These
are the same blocks Anadarko and its joint venture 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
joint venture partners will spend a minimum of $55 million. Anadarko and its
joint venture 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. To date, 640 miles of proprietary 2-D seismic
data have been acquired following the PSA amendment, which is under evaluation.
During 2002, Anadarko and its joint venture partners drilled three
exploration wells one of which was successful. The Hassi Berkine North East
(HBNE) #1 well, located in Block 404, just east of the HBN field, resulted in an
oil discovery. A production test conducted in January 2003 flowed at a rate of 4
MBbls/d of oil. The Company is evaluating options for connecting this discovery
to existing infrastructure. A fourth exploration well, Sif Fatima South West #1
located in Block 404, was drilled in early 2003 and the results are currently
being evaluated.
The license for Block 406b has a three-year initial term. A work program
commitment includes seismic acquisition and one exploration well. A 735 mile
proprietary 2-D seismic acquisition program has been completed on this 686,000
acre block, located in the Berkine basin to the east of Anadarko's other license
areas.
The license for Block 403c/e has a three-year initial term and increases
Anadarko's gross acreage position by 399,000 acres in the Berkine basin. A work
program commitment includes seismic acquisition and one exploration well.
Political unrest continues in Algeria. Anadarko continually monitors 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 unable to predict with certainty any effect the current
situation may have on activity planned for 2003 and beyond. However, the
situation has had no material effect to date on the Company's operations in
Algeria, where the Company has had activities since 1989. 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 interests in two non-operated offshore producing properties in
Australia and an interest in a non-operated producing property in Egypt. The
Company currently has exploration projects in Tunisia, Qatar, Oman, Gabon,
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 117 MMBbls of crude oil, condensate and NGLs and 144 Bcf of gas at
year-end 2002. During 2002, net production from the Company's other
international properties was 22 MBbls/d of crude oil, condensate and NGLs, or 4%
of the Company's total production volumes. Anadarko participated in a total of
10 wells in its other international locations during 2002 with a success rate of
50%. Drilling results included five oil wells and five dry holes. Anadarko has
24,896,000 gross (10,435,000 net) undeveloped lease acres and 569,000 gross
(155,000 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 consists of the Oritupano-Leona
contract area, a risk service contract in which the Company has a 45%
participating interest. The area covers 395,000 gross (178,000 net) acres and
had approximately 272 producing wells at year-end 2002. Oil sales volumes from
the area averaged 13 MBbls/d net during 2002. The development and exploitation
program in 2002 included two new well completions and the conversion of 13 idle
wells to producing wells. During 2003, the Company expects to continue with the
development of the Oritupano-Leona contract area, focusing most of the
activities on re-completing wells and increasing fluid handling capacities
within the field.
Currently, there is political unrest in Venezuela. Due to a national
strike, production deliveries from the Oritupano-Leona area were halted in April
and December 2002. Production resumed in January 2003 at lower
levels and is expected to be back at full production by the second quarter of 2003. Anadarko is unable to predict with certainty any effect the current situation may have on activity planned for 2003 and beyond. However, the situation is not expected to have a material adverse effect on the consolidated results of operations or financial position of the Company.
QATAR The Company acquired an additional interest and took over operatorship of
offshore Qatar Blocks 12 and 13 during 2002. Anadarko now has a 92.5% interest
in the Al Rayyan field, which is part of an Exploration and Production Sharing
Agreement covering Blocks 12 and 13. Production from the Al Rayyan field, which
is located in the northern part of Block 12, averaged 14 MBbls/d of oil (7
MBbls/d net) during 2002. The horizontal wells for the phase I field
re-development were completed in 2002. In addition, process and utilities
modules were constructed and installed on a permanent production facility.
Approximately $40 million is budgeted for 2003 to complete the construction and
installation of this offshore production facility, perform phase II development
drilling and drill an exploration well on the southern part of Block 12.
Following phase II, field production is expected to more than double. Evaluation
of the remaining exploration potential of Block 12 was initiated in 2002 and
should be completed in early 2003.
During 2002, the Company began a seismic feasibility study on Block 13,
which will serve to define a seismic program expected to be acquired in 2003.
Anadarko also has a 49% interest in an Exploration and Production Sharing
Agreement covering offshore Block 11. During 2002, an evaluation of the
remaining exploration potential on Block 11 was performed. The results of that
study have been presented to Qatar Petroleum, with additional discussions
scheduled for early 2003.
OMAN Anadarko is the operator of an exploration and development project in the Hafar field on Block 30 in Oman. Anadarko plans to drill two wells in 2003. The first exploration well, Hamrat Duru #3, began drilling in February 2003 and is intended to test the gas potential of the large Hamrat Duru structure. The second well, the Nadir #2, will follow and is intended to delineate and extend the Hafar/Al Sahwa trend. Anadarko has a 100% interest in the field. Gas production will be sold to the Oman government under a long-term sales agreement.
EGYPT Anadarko has a 25% non-operated interest in the Zaafarana field offshore Egypt. The Company's net volumes in Egypt for 2002 averaged 1 MBbls/d of oil.
AUSTRALIA Anadarko has a 15% non-operated interest in production facilities in the Jabiru and Challis fields (ACL123) offshore Northwest Shelf. The Company's net volumes from these fields during 2002 averaged 1 MBbls/d of oil. Anadarko relinquished its interests in four licenses (ACL 4, AC/P 25, 26 and 27) in the Timor Sea following three unsuccessful wells in 2002. Anadarko has a 30% interest in four exploration permits, EPP 28, 29, 30 and 31 covering 15,500,000 gross acres offshore southern Australia in the Great Australian Bight. A deepwater exploration well is scheduled for drilling on EPP 29 in early 2003.
TUNISIA The Company increased its interest from 47% to 61% in 2002 and is the operator of the 1,100,000 acre Anaguid Block in the Ghadames basin of Tunisia. The acreage is on trend with the Company's discoveries in Algeria to the west. The CEM-1 and the SEA-1 wells are expected to spud in early 2003. Both wells will target the Silurian Acacus formation. In early 2003, Anadarko completed the drilling of an unsuccessful exploration well on the Sanrhar Block.
WEST AFRICA During 2002, the Company obtained a 55% interest in the Gryphon
Block, a 2,400,000 acre tract offshore Gabon in the Gamba pre-salt trend. An
exploration well, the Pembi #1, is expected to spud by the third quarter of
2003.
Anadarko is the operator and holds a 50% interest in the Agali Block
offshore Gabon. During 2002, 3-D seismic data was processed and evaluated.
Drilling may occur in late 2003 but will be after the resolution of a boundary
dispute between Gabon and its neighbor to the north, Equatorial Guinea.
Anadarko drilled one exploration well in West Africa during 2002 on the
Marine IX Block offshore the Republic of Congo. The Rita #1 well encountered
thin gas pay but was deemed non-commercial. The Company is considering marketing
its 42% interest in the block during the first quarter of 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 adjacent non-operated
License 006. The licenses cover a total of 617,000 acres. In 2002, the Company
integrated seismic data as part of a comprehensive license and basin evaluation.
In 2003, the Company will complete these studies and further develop a prospect
inventory. The Company has no outstanding drilling commitments in the region.
In the United Kingdom Continental Shelf, Tranches 21 and 63 were
relinquished in 2002. In Tranche 61, (7.5% interest) 49,000 acres surrounding
two gas discoveries have been retained pending further evaluation.
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 2,000,000 acres on the Black Sea Continental Shelf and extending 50 miles offshore. In 2002, the Company evaluated proprietary seismic data and plans to seek a partner to share cost and reduce risk in future seismic or drilling activities in 2003.
DRILLING PROGRAMS
The Company's 2002 drilling program focused on known oil and gas provinces in the United States (Lower 48, Alaska and Gulf of Mexico), Canada and Algeria. Exploration activity consisted of 114 wells, including 48 wells in the Lower 48, 6 wells in Alaska, 7 wells offshore in the Gulf of Mexico, 46 wells in Canada, 3 wells in Algeria and 4 wells at other international locations. Development activity consisted of 835 wells, which included 429 wells in the Lower 48, 8 wells in Alaska, 16 wells offshore in the Gulf of Mexico, 345 wells in Canada, 31 wells in Algeria and 6 wells at other international locations.
DRILLING STATISTICS
The following table shows the results of the oil and gas wells drilled and tested:
NET EXPLORATORY NET DEVELOPMENT
------------------------------ ------------------------------
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL TOTAL
---------- --------- ----- ---------- --------- ----- -------
2002
United States 34.0 13.8 47.8 275.2 5.1 280.3 328.1
Canada 30.6 6.8 37.4 305.6 4.0 309.6 347.0
Algeria 0.5 1.0 1.5 7.3 0.7 8.0 9.5
Other International -- 3.7 3.7 3.7 0.9 4.6 8.3
----- ----- ----- ----- ----- ----- -------
Total 65.1 25.3 90.4 591.8 10.7 602.5 692.9
----- ----- ----- ----- ----- ----- -------
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
----- ----- ----- ----- ----- ----- -------
|
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, 2002:
WELLS IN THE PROCESS
OF DRILLING OR WELLS SUSPENDED OR
IN ACTIVE COMPLETION WAITING ON COMPLETION
------------------------- -------------------------
EXPLORATION DEVELOPMENT EXPLORATION DEVELOPMENT
----------- ----------- ----------- -----------
UNITED STATES
Gross 4 47 12 31
Net 3.3 33.9 6.1 13.7
CANADA
Gross 11 21 2 26
Net 8.5 17.3 1.4 20.4
ALGERIA
Gross -- 4 -- 1
Net -- 0.9 -- 0.2
OTHER INTERNATIONAL
Gross 1 1 -- 2
Net 1.0 0.5 -- 1.9
TOTAL
Gross 16 73 14 60
Net 12.8 52.6 7.5 36.2
|
PRODUCTIVE WELLS
As of December 31, 2002, the Company had a working interest ownership in productive wells as follows:
OIL WELLS* GAS WELLS*
---------- ----------
UNITED STATES
Gross 9,089 10,106
Net 6,207.0 6,420.3
CANADA
Gross 1,037 3,530
Net 646.4 2,811.4
ALGERIA
Gross 99 --
Net 21.4 --
OTHER INTERNATIONAL
Gross 302 --
Net 136.2 --
TOTAL
Gross 10,527 13,636
Net 7,011.0 9,231.7
|
* Includes wells containing multiple completions as follows:
Gross 191 1,682 Net 160.9 1,319.3 |
MARKETING AND GATHERING PROPERTIES AND ACTIVITIES
MARKETING The Company's marketing department actively manages sales of its oil
and gas through Anadarko Energy Services Company, Anadarko, Anadarko Canada
Corporation and Anadarko Holding. The Company markets its production to
creditworthy customers at competitive prices, maximizing realized prices while
managing credit exposure. The Company purchases some physical volumes for resale
primarily from partners and producers near Anadarko's production. These
purchases allow the Company to aggregate larger volumes of gas and attract
larger, creditworthy customers, which in turn enhances the value of the
Company's production.
The Company 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. The Company has the 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 instruments. However, the Company does not
engage in market-making practices nor does it trade in any non-energy-related
commodities. The Company's marketing function does not engage in round-trip
trades and does not participate in any marketing-related partnerships.
GAS GATHERING Anadarko owns and operates seven major gas gathering systems in
the United States, 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; CJV/SEC Gathering System in the Carthage field of east Texas; and
Vernon Gathering System in the Vernon field of north Louisiana.
The Company's major gathering systems have more than 3,000 miles of
pipeline connecting about 3,300 wells and averaged more than 730 MMcf/d of gas
throughput in 2002. In addition, Anadarko operates numerous other smaller gas
gathering systems.
MINERALS PROPERTIES AND ACTIVITIES
The Company's minerals properties contribute to 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. Because of the high extraction and transportation costs,
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 3
million tons of coal per year.
The world's largest known deposit of trona, comprising 90% of the world's
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. 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. 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 1 million tons per year.
SEGMENT AND GEOGRAPHIC INFORMATION
Information on operations by segment and geographic location is contained in Note 13 of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
EMPLOYEES
As of December 31, 2002, the Company had about 3,800 employees. Relations between the Company and its employees are considered to be satisfactory. The Company has had no significant work stoppages or strikes pertaining to its employees.
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
Anadarko's ratios of earnings to fixed charges was 3.83 and earnings to
combined fixed charges and preferred stock dividends was 3.74 for the year ended
December 31, 2002. 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 was 7.35 and earnings to combined fixed charges and
preferred stock dividends was 6.80 for the year ended December 31, 2000.
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.
ITEM 2. PROPERTIES
Information on Properties is contained in Item 1 of this Form 10-K and in Note 17 -- Commitments of the Notes to Consolidated Financial Statements under Item 8 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 Anadarko Holding 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 Civil False Claims Act,
the Company could be subject to a variety of sanctions, including treble damages
and substantial monetary fines. Motions to dismiss on the grounds that
plaintiffs did not provide new information for the government to file suit upon
were filed in January 2003, with a hearing date expected in May 2003.
A group of royalty owners purporting to represent Anadarko Holding'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 was asserted. The Company appealed the class certification order. A
favorable decision from the Houston Court of Appeals decertified the class. The
royalty owners did not appeal this matter to the Texas Supreme Court and the
decision from the Houston Court of Appeals became final in the second quarter of
2002. The royalty owners recently filed a new petition alleging that the class
may properly be brought so long as "sub-class" groups are broken out. The
Company is vigorously contesting this new petition.
A class action lawsuit titled 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. It is uncertain when
the trial court will render its ruling.
CITGO LITIGATION CITGO Petroleum Corporation's (CITGO) claims arise out of an Asset Purchase and Contribution Agreement in 1987 whereby Anadarko Holding'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 Anadarko Holding 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, Anadarko Holding 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 Anadarko Holding. In conjunction with this matter, Anadarko Holding sued Continental Insurance for denial of coverage for claims related to this dispute. Anadarko Holding and Continental Insurance settled the insurance coverage litigation which resulted in Continental Insurance paying a portion of Anadarko Holding's claims. Negotiations and discussions with CITGO continue. Anadarko Holding has offered to settle all outstanding issues for approximately $4 million and a liability for this amount has been accrued.
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 charged 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 reached a settlement agreement with PanEnergy that required 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 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 quarter of 2003 that may result in payment of about $6
million by the Company. A provision was charged against income in 2001.
Other Litigation The Company has a reserve of about $2 million for Kansas ad valorem tax refunds. This amount reflects all principal and interest that may be due at the conclusion of all regulatory proceedings and litigation to parties other than PanEnergy.
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 2002.
EXECUTIVE OFFICERS OF THE REGISTRANT
AGE AT END
NAME OF 2003 POSITION
---- ---------- --------
Robert J. Allison, Jr. 64 Chairman of the Board
John N. Seitz 52 President and Chief Executive Officer
Charles G. Manley 59 Executive Vice President, Administration
Michael E. Rose 56 Executive Vice President and Chief Financial
Officer
William D. Sullivan 47 Executive Vice President, Exploration and
Production
Rex Alman III 52 Senior Vice President, Algeria
Michael D. Cochran 61 Senior Vice President, Strategy and Planning
James R. Larson 53 Senior Vice President, Finance
Richard J. Sharples 56 Senior Vice President, Marketing and Minerals
Bruce H. Stover 54 Senior Vice President, Worldwide Business
Development
Robert P. Daniels 44 Vice President, Canada
Diane L. Dickey 47 Vice President and Controller
James J. Emme 47 Vice President, Exploration
Morris L. Helbach 58 Vice President, Information Technology Services
and Chief Information Officer
Richard A. Lewis 59 Vice President, Human Resources
J. Anthony Meyer 45 Vice President, International and Alaska
Operations
Mark L. Pease 47 Vice President, Domestic Operations
Gregory M. Pensabene 53 Vice President, Government Relations and Public
Affairs
Albert L. Richey 54 Vice President and Treasurer
Charlene A. Ripley 39 Vice President
Suzanne Suter 57 Vice President, Corporate Secretary, Chief
Governance Officer and Interim General Counsel
A. Paul Taylor, Jr. 54 Vice President, Investor Relations
Donald R. Willis 53 Vice President, Corporate Services
|
Mr. Allison relinquished the role of Chief Executive Officer in 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 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. Prior to that, Mr. Seitz served as Senior Vice President,
Exploration since 1995. 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 since
1993. He has worked for the Company since 1974.
Mr. Rose was named Executive Vice President and Chief Financial Officer in
2000. Prior to this position, he served as Senior Vice President, Finance and
Chief Financial Officer since 1993. He has worked for the Company since 1978.
Mr. Sullivan was named Executive Vice President, Exploration and Production
in 2001. Prior to this position, he served as Vice President,
Operations -- International, Gulf of Mexico and Alaska since 2000, Vice
President, International Operations since 1998 and Vice President, Algeria since
1995. He has worked for the Company since 1981.
Mr. Alman was named Senior Vice President, Algeria in 2002 and he was named
Senior Vice President, Domestic Operations in 2001. Prior to this position, he
served as Vice President, Domestic Operations since 1997. 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 since 1997. He
has worked for the Company since 1987.
Mr. Larson was named Senior Vice President, Finance in 2002. Prior to this
position, he served as Vice President and Controller since 1995. He has worked
for the Company since 1983.
Mr. Sharples was named Senior Vice President, Marketing and Minerals in
2001. Prior to this position, he served as Vice President, Marketing since he
joined the Company in 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 served in various managerial roles in the Exploration Department
for Anadarko Algeria Company LLC. He has worked for the Company since 1985.
Ms. Dickey was named Vice President and Controller in 2002. Prior to this
position, she served as Assistant Controller since 1995. She has worked for the
Company since 1978.
Mr. Emme was named Vice President, Exploration in 2001 and named Vice
President, Canada in 2000. Prior to this he served in various managerial roles
in the Exploration Department. Mr. Emme 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 at Conoco, Inc.
Mr. Lewis was named Vice President, Human Resources in 1995. He joined the
Company as Manager Human Resources in 1985.
Mr. Meyer was named Vice President, International and Alaska Operations in
2002 and was named Vice President, Algeria in 2001. Prior to this position, he
served as President and General Manager, Anadarko Algeria Company, LLC and in
other managerial roles for Anadarko Algeria Company, LLC and in the Operations
Department. He has worked for the Company since 1981.
Mr. Pease was named Vice President, Domestic Operations in 2002. Prior to
this position, he served as Vice President, International and Alaska Operations
since September 2001, 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 has worked for the Company since
1979.
Mr. Pensabene joined Anadarko in 1997 as Vice President, Government
Relations. Prior to joining Anadarko, he was a partner in the law firm of Muys &
Pensabene from 1996 to 1997.
Mr. Richey was named Vice President and Treasurer in 1995. He joined the
Company as Treasurer in 1987.
Ms. Ripley was named Vice President in 2003. Prior to this position, she
served as Vice President, General Counsel and Secretary of Anadarko Canada
Corporation and its predecessor since 1998. She has worked for the Company since
1997.
Ms. Suter was named Vice President, Corporate Secretary and Chief
Governance Officer in 2002 and in January 2003 she was given the additional
position of Interim General Counsel. She has served as Associate General Counsel
since 2001 and Corporate Secretary since 1987. She has worked for the Company
since 1986.
Mr. Taylor was named Vice President, Investor Relations in 1999. Prior to
this position, he served as Vice President, Corporate Communications since 1987.
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.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Information on the market price and cash dividends declared per share of
common stock is included in the Stockholder Information in the Anadarko
Petroleum Corporation 2002 Annual Report (Annual Report) which is incorporated
herein by reference.
As of February 24, 2003, there were approximately 22,000 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, 2002.
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
millions ------- ------- ------- -------
2002 $ 18 $ 18 $ 20 $ 24
2001 $ 12 $ 13 $ 12 $ 20
|
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 of this Form 10-K.
Equity Compensation Plan Table The following table sets forth information with respect to the equity compensation plans available to directors, officers and employees of the Company as of December 31, 2002:
(C)
NUMBER OF SECURITIES
(A) (B) REMAINING AVAILABLE
NUMBER OF SECURITIES WEIGHTED-AVERAGE FOR FUTURE ISSUANCE
TO BE ISSUED UPON EXERCISE PRICE OF UNDER EQUITY
EXERCISE OF OUTSTANDING COMPENSATION PLANS
OUTSTANDING OPTIONS, OPTIONS, WARRANTS (EXCLUDING SECURITIES
PLAN CATEGORY WARRANTS AND RIGHTS AND RIGHTS REFLECTED IN COLUMN(A))
------------- -------------------- ----------------- -----------------------
Equity compensation plans
approved by security holders 15,328,369 $42.68 2,498,391
Equity compensation plans not
approved by security holders -- -- --
---------- ------ ---------
Total 15,328,369 $42.68 2,498,391
|
Unregistered Securities 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 initial purchaser of the ZYP-CODES was Lehman Brothers Inc. The ZYP-CODES
were subsequently registered on a Form S-3 effective in July 2001.
In April 2001, Anadarko Finance Company, a wholly-owned finance subsidiary
of Anadarko, issued $1.3 billion in notes to qualified institutional buyers
under Rule 144A and non-U.S. persons under Regulation S. The initial purchaser
was Credit Suisse First Boston Corporation. The notes were subsequently
registered on a Form S-4 effective in July 2001.
For additional information, see Note 7 -- Debt of the Notes to Consolidated
Financial Statements under Item 8 of this Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
See Five Year Financial Highlights in the Annual Report, which is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL RESULTS
SELECTED FINANCIAL DATA
2002 2001 2000
millions except per share amounts ------ ------ ------
Revenues $3,860 $4,718 $2,911
Costs and expenses 2,435 5,081 1,559
Interest expense 203 92 93
Other (income) expense 15 (65) (167)
Net income (loss) available to common stockholders before
cumulative effect of change in accounting principle $ 825 $ (183) $ 813
Net income (loss) available to common stockholders $ 825 $ (188) $ 796
Earnings (loss) per share -- before cumulative effect
of change in accounting principle -- basic $ 3.32 $(0.73) $ 4.42
Earnings (loss) per share -- before cumulative effect
of change in accounting principle -- diluted $ 3.21 $(0.73) $ 4.25
Earnings (loss) per share -- basic $ 3.32 $(0.75) $ 4.32
Earnings (loss) per share -- diluted $ 3.21 $(0.75) $ 4.16
|
NET INCOME Anadarko's net income available to common stockholders for 2002
totaled $825 million, or $3.21 per share (diluted), compared to net loss
available to common stockholders for 2001 of $188 million, or $0.75 per share
(diluted). Net loss for 2001 includes non-cash charges of $2.5 billion ($1.6
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. See
Critical Accounting Policies. Anadarko had net income available to common
stockholders in 2000 of $796 million or $4.16 per share (diluted).
In January 2002, the Company discontinued the amortization of goodwill in
accordance with Statement of Financial Accounting Standards (SFAS) No. 142,
"Goodwill and Other Intangible Assets." See Note 3 -- Goodwill in the Notes to
Consolidated Financial Statements under Item 8 of this Form 10-K.
REVENUES
2002 2001 2000
millions ------ ------ ------
Gas sales $1,835 $2,952 $1,615
Oil and condensate sales 1,690 1,397 946
Natural gas liquids sales 222 256 264
Other sales 113 113 86
------ ------ ------
Total $3,860 $4,718 $2,911
------ ------ ------
|
During 2002, the Company adopted Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." In accordance with EITF Issue No. 02-3, marketing sales and purchases resulting in physical settlement for prior periods have been reclassified to show net marketing margins as revenues. The marketing margins related to the Company's equity production are included in gas sales, oil and condensate sales and natural gas liquids (NGLs) sales and are reflected in commodity prices. The marketing margin related to purchases of third-party commodities is included in other sales. This reclassification had no effect on reported net income or cash flow.
Anadarko's total revenues for 2002 were down $858 million or 18% compared
to total revenues in 2001 due primarily to a significant decrease in natural gas
prices, as well as decreases in natural gas volumes, partially offset by higher
crude oil prices and volumes.
Total revenues for 2001 increased $1.8 billion or 62% compared to 2000 due
primarily to a significant increase in sales volumes, partially offset by a
decrease in crude oil, condensate and NGLs prices.
ANALYSIS OF OIL AND GAS SALES VOLUMES
2002 2001 2000
---- ---- ----
BARRELS OF OIL EQUIVALENT (MMBOE)
United States 130 144 83
Canada 35 34 12
Algeria 24 8 10
Other International 8 13 7
--- --- ---
Total 197 199 112
--- --- ---
BARRELS OF OIL EQUIVALENT PER DAY (MBOE/D)
United States 355 394 226
Canada 97 93 34
Algeria 65 22 26
Other International 22 37 20
--- --- ---
Total 539 546 306
--- --- ---
|
During 2002, Anadarko sold 197 MMBOE, a decrease of 2 MMBOE or 1% compared to sales of 199 MMBOE in 2001. The decrease in volumes for 2002 was primarily due to a decrease of 14 MMBOE due to operations in the United States, primarily offshore, and in Texas and Louisiana, and a decrease of 4 MMBOE related to the disposition of operations in Guatemala and Argentina in 2001. The decrease in volumes in the United States was primarily a result of natural production declines and a decrease in development drilling in late 2001 and early 2002 in response to lower commodity prices. These decreases were offset by an increase of 16 MMBOE in Algeria due to the expansion of production facilities. The Company's sales volumes were up 87 MMBOE or 78% in 2001 compared to 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 Anadarko Holding Company (Anadarko Holding) merger transaction 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 Petroleum Corp. (Berkley) in March 2001, 6 MMBOE from operations in the Bossier play in Texas and Louisiana and 5 MMBOE from operations in Alaska. Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to help manage volumes and mitigate the effect of price volatility, which is likely to continue in the future. See Derivative Instruments under Item 7a of this Form 10-K.
NATURAL GAS SALES VOLUMES AND AVERAGE PRICES
2002 2001 2000
------ ------ -----
UNITED STATES (BCF) 507 573 338
MMcf/d 1,390 1,569 922
Price per Mcf $ 2.84 $ 4.23 $4.22
CANADA (BCF) 135 121 46
MMcf/d 370 331 127
Price per Mcf $ 2.93 $ 4.38 $4.09
OTHER INTERNATIONAL (BCF) -- 1 1
MMcf/d -- 4 3
Price per Mcf $ -- $ 1.22 $1.08
TOTAL (BCF) 642 695 385
MMcf/d 1,760 1,904 1,052
Price per Mcf $ 2.86 $ 4.25 $4.19
|
Anadarko's natural gas sales volumes in 2002 were down 53 Bcf or 8%
compared to 2001. The decrease in volumes was due primarily to a decrease of 66
Bcf from operations within the United States, primarily offshore and in Texas,
partially offset by an increase of 14 Bcf from operations in Canada primarily
due to the Berkley acquisition in 2001. 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 Anadarko Holding merger transaction
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.
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 natural gas price in 2002 decreased 33% compared to
2001. The decrease in prices during 2002 were attributed to a severe decline in
natural gas demand as a result of high prices in early 2001, followed by a
national economic downturn and mild summer weather in 2001. The Company's
average natural 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. As of the end of
January 2003, the Company had hedged 38% and 22% of the Company's natural gas
production that is expected to be produced during 2003 and 2004, respectively.
As a result, the remaining future natural gas volumes are subject to continued
volatility based on fluctuations in market prices. See Derivative Instruments
under Item 7a of this Form 10-K.
QUARTERLY NATURAL GAS SALES VOLUMES AND AVERAGE PRICES
2002 2001 2000
------ ------ ------
FIRST QUARTER
Bcf 162 164 44
MMcf/d 1,805 1,822 486
Price per Mcf $ 2.26 $ 6.89 $ 2.63
SECOND QUARTER
Bcf 163 184 49
MMcf/d 1,791 2,018 536
Price per Mcf $ 3.05 $ 4.58 $ 3.39
THIRD QUARTER
Bcf 162 176 138
MMcf/d 1,764 1,913 1,498
Price per Mcf $ 2.64 $ 3.00 $ 3.86
FOURTH QUARTER
Bcf 155 171 154
MMcf/d 1,682 1,863 1,676
Price per Mcf $ 3.50 $ 2.63 $ 5.19
|
CRUDE OIL AND CONDENSATE SALES VOLUMES AND AVERAGE PRICES
2002 2001 2000
------ ------ ------
UNITED STATES (MMBBLS) 31 34 15
MBbls/d 85 93 40
Price per barrel $23.07 $23.08 $28.59
CANADA (MMBBLS) 12 13 4
MBbls/d 33 35 12
Price per barrel $19.31 $18.18 $27.33
ALGERIA (MMBBLS) 24 8 10
MBbls/d 65 22 26
Price per barrel $24.38 $23.97 $28.73
OTHER INTERNATIONAL (MMBBLS) 8 13 7
MBbls/d 22 36 20
Price per barrel $19.92 $14.35 $18.35
TOTAL (MMBBLS) 75 68 36
MBbls/d 205 186 98
Price per barrel $22.55 $20.56 $26.42
|
Anadarko's crude oil and condensate sales volumes for 2002 increased 7 MMBbls or 10% compared to 2001. The increase was due primarily to an increase of approximately 16 MMBbls from operations in Algeria primarily due to the expansion of production facilities and an increase of 2 MMBbls due to the acquisition of producing properties in Qatar in 2001. These increases were partially offset by a decrease of 4 MMBbls related primarily to the sale of producing properties in Guatemala and Argentina in 2001, a decrease of 3 MMBbls related to operations in the United States, primarily offshore, and a decrease of 3 MMBbls related to operations in Venezuela primarily due to higher oil prices. See Critical Accounting Policies.
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
Anadarko Holding merger transaction 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. Production of oil usually is not affected
by seasonal swings in demand or in market prices.
The Company's average realized crude oil price in 2002 increased 10%
compared to 2001. The increase in crude oil prices in 2002 was due primarily to
continued uncertainty of the situation in the middle east, the oil workers
strike in Venezuela and a colder than normal winter late in 2002 which increased
oil demand in the United States. Anadarko's average realized crude oil prices
for 2001 decreased 22% 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. As of the end of January 2003, the Company had hedged 35% and 3% of
the Company's crude oil production that is expected to be produced during 2003
and 2004, respectively. As a result, the remaining future oil and condensate
volumes are subject to continued volatility based on fluctuations in market
prices.
QUARTERLY CRUDE OIL AND CONDENSATE SALES VOLUMES AND AVERAGE PRICES
2002 2001 2000
------ ------ ------
FIRST QUARTER
MMBbls 19 17 4
MBbls/d 212 186 49
Price per barrel $18.54 $21.92 $26.36
SECOND QUARTER
MMBbls 19 18 3
MBbls/d 205 192 38
Price per barrel $22.57 $21.61 $26.99
THIRD QUARTER
MMBbls 18 18 13
MBbls/d 191 192 141
Price per barrel $24.50 $21.82 $27.53
FOURTH QUARTER
MMBbls 20 16 15
MBbls/d 214 175 161
Price per barrel $24.67 $16.64 $25.33
|
NATURAL GAS LIQUIDS SALES VOLUMES AND AVERAGE PRICES
2002 2001 2000
------ ------ ------
TOTAL (MMBBLS) 15 15 12
MBbls/d 41 42 33
Price per barrel $14.80 $16.55 $21.70
|
The Company's NGLs sales volumes in 2002 were essentially flat compared to 2001. NGLs sales volumes in 2001 increased 25% compared to 2000 primarily due to the increase in natural gas sales volumes. The 2002 average NGLs prices decreased 11% compared to 2001. High levels of NGLs inventories in the United States during the first half of 2002, coupled with lower demand for NGLs by the petrochemical industry, have caused NGLs prices to decline. The 2001 average NGLs prices decreased 24% compared to 2000 due primarily to a decrease in demand. NGLs production is dependent on natural gas prices and the economics of processing the natural gas volumes to extract NGLs.
COSTS AND EXPENSES
2002 2001 2000
millions ------ ------ ------
Operating expenses $ 747 $ 769 $ 487
Administrative and general 314 292 270
Depreciation, depletion and amortization 1,121 1,154 593
Other taxes 214 247 128
Impairments related to oil and gas properties 39 2,546 50
Amortization of goodwill -- 73 31
------ ------ ------
Total $2,435 $5,081 $1,559
------ ------ ------
|
During 2002, Anadarko's costs and expenses decreased $2.6 billion or 52%
compared to 2001 due to the following factors:
-- Operating expenses decreased $22 million (3%) primarily due to a
decrease in costs associated with processing NGLs.
-- Administrative and general expenses increased $22 million (8%). An
increase of $58 million due primarily to increases in benefits and
salaries expenses associated with the Company's growing workforce was
partially offset by a $31 million decrease in merger related expenses
and a $5 million decrease related to an adjustment to provisions for
doubtful accounts.
-- Depreciation, depletion and amortization (DD&A) expense decreased $33
million (3%). The decrease is due primarily to a lower DD&A rate for oil
and gas properties in 2002 as a result of ceiling test impairments in
the third quarter of 2001 and a decrease related to slightly lower
production volumes in 2002.
-- Other taxes decreased $33 million (13%). The decrease is primarily due
to a decrease in production taxes as a result of lower commodity prices
and slightly lower production volumes in 2002.
-- Impairments in 2002 relate primarily to oil and gas properties in Congo
($16 million), Oman ($10 million), Australia ($7 million) and Tunisia
($5 million) primarily due to unsuccessful exploration activities.
-- Amortization of goodwill was discontinued in 2002 in accordance with
SFAS No. 142.
During 2001, Anadarko's costs and expenses increased $3.5 billion or 226%
compared to 2000 due to the following factors:
-- Operating expenses increased $282 million (58%) primarily due to a
significant increase in the number of producing wells as a result of
mergers and acquisitions in 2000 and 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 $22 million (8%). An
increase of $67 million due primarily to the Company's expanded
workforce resulting from the Anadarko Holding merger transaction in
mid-2000 and higher costs associated with the Company's growing
workforce was partially offset by a decrease in provisions for doubtful
accounts of $23 million and a $22 million decrease in merger related
expenses.
-- DD&A expense increased $561 million (95%). About 80% of the increase was
due to the increase in volumes as a result of mergers and acquisitions
in 2000 and 2001 and significant development activity. The remaining
increase is due to increases in the DD&A rate, which is also due to the
merger and acquisitions.
-- 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 ($1.7 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 Anadarko
Holding merger transaction in mid-2000 ($32 million) and the Berkley
acquisition in 2001 ($10 million).
INTEREST EXPENSE
2002 2001 2000
millions ----- ----- -----
Gross interest expense $ 358 $ 301 $ 193
Capitalized interest (155) (209) (100)
----- ----- -----
Net interest expense $ 203 $ 92 $ 93
----- ----- -----
|
Anadarko's gross interest expense has increased over the past three years
due primarily to the Anadarko Holding merger transaction 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 2002 increased 19% compared to 2001 primarily due to higher average debt
outstanding in 2002 primarily because of acquisitions in 2001 and slightly
higher interest rates. Gross interest expense in 2001 increased 56% compared to
2000 primarily due to the Anadarko Holding merger transaction in mid-2000 and
the Berkley acquisition in 2001 which resulted in higher average borrowings
during 2001. See Capital Resources and Liquidity and Outlook on Liquidity.
In 2002, capitalized interest decreased by 26% compared to 2001 primarily
due to a decrease in capitalized costs that qualify for interest capitalization.
In 2001, capitalized interest increased by 109% compared to 2000 primarily due
to an increase in costs that qualify for interest capitalization related to the
Anadarko Holding merger transaction in mid-2000 and the Berkley acquisition in
2001. 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
2002 2001 2000
millions ----- ----- -----
Firm transportation keep-whole contract valuation $(35) $(91) $(175)
Unrealized (gain) loss on derivative instruments 33 (18) --
Gas sales contracts -- accretion of discount 11 14 --
Foreign currency exchange 1 29 7
Other 5 1 1
---- ---- -----
Total $ 15 $(65) $(167)
---- ---- -----
|
Other income in 2002 decreased $80 million compared to 2001 due primarily to a $56 million decrease in income related to the effect of lower market values for firm transportation subject to a keep-whole agreement and a $51 million decrease related to unrealized (gain) loss on derivative instruments due to increased commodity prices and hedging activity, partially offset by a $28 million decrease in foreign currency exchange losses primarily due to the restructuring of Canadian debt and changes in the Canadian exchange rate. Other income in 2001 decreased $102 million 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 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. See Derivative Instruments and Foreign Currency Risk under Item 7a of this Form 10-K.
INCOME TAX EXPENSE (BENEFIT)
2002 2001 2000
millions ---- ----- ----
Income tax expense (benefit) $376 $(214) $602
|
For 2002, income taxes increased $590 million compared to 2001. Income
taxes for 2001 decreased $816 million compared to 2000. Income taxes for 2001
include a benefit of approximately $962 million related to the impairment of the
carrying value of oil and gas properties in the United States, Canada and
Argentina as a result of low natural gas and crude oil prices at the end of the
third quarter of 2001.
Excluding the effect of the impairment and related tax benefit in 2001,
income taxes for 2002 decreased primarily due to the decrease in earnings before
income taxes. Excluding the effect of the impairment and the
related tax benefit in 2001, the increase in 2001 income taxes compared to 2000
was primarily due to the increase in earnings before income taxes.
The effective tax rate for 2002, 2001 and 2000 was 31%, 55% and 42%,
respectively. The variances in the effective tax rate for 2002 and 2000 from the
statutory rate of 35% were due primarily to changes in income taxes related to
foreign operations. The effective tax rate for 2001 was 35%, excluding the
effect of the impairment and the related tax benefit.
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 sells significant volumes to major
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 Anadarko Holding. The Company markets its production to
customers at competitive prices, maximizing realized prices while managing
credit exposure. The market knowledge gained through the marketing effort is
valuable to the corporate decision making process.
The Company also conducts trading activities for the purpose of generating
profits on or from exposure to changes in market prices of gas, 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, typically, is a net short position that is offset by the Company's
natural long position as a producer. The Company's marketing function does not
engage in round-trip trades or participate in any marketing-related
partnerships. 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
Instruments under Item 7a of this Form 10-K.
During 2002, all segments of the natural gas market experienced increased
scrutiny of their financial condition, liquidity and credit. This has been
reflected in rating agency credit downgrades of many merchant energy trading
companies. In 2002, Anadarko has not experienced any material financial losses
associated with credit deterioration of third-party gas purchasers; however, in
certain situations the Company has declined to transact with some counterparties
and changed its sales terms to require some counterparties to pay in advance or
post letters of credit.
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 portfolio of exploration
and development prospects should position Anadarko to continue to participate in
this growth. AES is a full-service marketing company offering supply assurance,
competitive pricing, risk management services and other services tailored to its
customers' needs. Approximately 40% of the Company's gas production was sold
through AES in 2002. The Company also purchases some physical volumes for resale
primarily from partners and producers near Anadarko's production. These
purchases allow the Company to aggregate larger volumes of gas and attract
larger, creditworthy customers, which in turn enhances the value of the
Company's production. The Company 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. The Company 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 instruments.
Anadarko Holding 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 (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, Anadarko
Holding agreed to pay Duke if transportation market values fall below the fixed
contract transportation rates, while Duke will pay Anadarko Holding 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
New York Mercantile Exchange (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 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.
In 2002, 2001 and 2000, approximately 29%, 31% and 56%, respectively, of
the Company's gas production was sold under long-term contracts to Duke. These
sales represent 13%, 21% and 24%, respectively, of total revenues in 2002, 2001
and 2000. Most of the Company's gas production sold to Duke 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 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 sold under 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 various derivative 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 $162 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.
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 and related derivatives as of December 31, 2002. The Company records income or loss 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.
FIRM
MARKETING TRANSPORTATION
AND TRADING KEEP-WHOLE TOTAL
millions ----------- -------------- -----
Fair value of contracts outstanding as of December 31,
2001 $17 $(82) $(65)
Contracts realized or otherwise settled during 2002 15 (26) (11)
Fair value of new contracts when entered into during
2002 7 -- 7
Other changes in fair value (44) 35 (9)
--- ---- ----
Fair value of contracts outstanding as of December 31,
2002 $(5) $(73) $(78)
--- ---- ----
|
FAIR VALUE OF CONTRACTS AS OF DECEMBER 31, 2002
------------------------------------------------------
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 $ (4) $ -- $ -- $ -- $ (4)
Prices based on models and other
valuation methods (1) -- -- -- (1)
FIRM TRANSPORTATION KEEP-WHOLE
Prices actively quoted $ (5) $ -- $ -- $ -- $ (5)
Prices based on models and other
valuation methods -- (40) (23) (5) (68)
TOTAL
Prices actively quoted $ (9) $ -- $ -- $ -- $ (9)
Prices based on models and other
valuation methods (1) (40) (23) (5) (69)
|
OPERATING RESULTS
DRILLING ACTIVITY During 2002, Anadarko participated in a total of 949 gross
wells, including 686 gas wells, 217 oil wells and 46 dry holes. This compares to
1,420 gross wells (970 gas wells, 375 oil wells and 75 dry holes) in 2001 and
709 gross wells (385 gas wells, 269 oil wells and 55 dry holes) in 2000. The
decrease in activity during 2002 reflects the Company's reduced spending for
development drilling in response to lower commodity prices in late 2001 and
early 2002. The increase in activity during 2001 was a result of mergers and
acquisitions in 2001 and 2000 and improved commodity prices at the beginning of
2001.
The Company's 2002 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
GAS OIL DRY TOTAL
----- ----- ---- -----
2002 EXPLORATORY
Gross 58 24 32 114
Net 45.2 19.9 25.3 90.4
2002 DEVELOPMENT
Gross 628 193 14 835
Net 444.2 147.6 10.7 602.5
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
|
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. For the 21st 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.
During 2002, Anadarko's worldwide reserve replacement was 112% of total
production of 196 MMBOE. The Company's worldwide reserve replacement in 2001 was
221% of total production of 201 MMBOE. The Company's worldwide reserve
replacement in 2000 was 1,059% of total production of 112 MMBOE. Over the last
five years, the Company's annual reserve replacement has averaged 368% of annual
production volumes.
Excluding mergers, acquisitions and divestitures, Anadarko's worldwide
reserve replacement for 2002 was 87% of total production compared to 173% for
2001 and 231% for 2000. The decrease in 2002 was partially due to a downward
price revision of 36 MMBOE in Venezuela. See Critical Accounting Policies.
Excluding mergers, acquisitions and divestitures, the Company's annual worldwide
reserve replacement over the past five years averaged 187% of annual production
volumes.
Anadarko continues to increase its energy reserves in the U.S. In 2002, the
Company replaced 185% of its U.S. production volumes with U.S. reserves. This
compares to a U.S. reserve replacement of 161% in 2001 and 855% in 2000. The
Company's U.S. reserve replacement for the five-year period 1998-2002 was 325%
of production. Excluding mergers, acquisitions and divestitures, Anadarko's U.S.
reserve replacement for 2002, 2001 and 2000 was 137%, 160% and 207%,
respectively, of total production. The Company's U.S. reserve replacement for
the five-year period 1998-2002 was 179% excluding mergers, acquisitions and
divestitures. By comparison, the most recent published U.S. industry average
(1997-2001) was 111% (Source: U.S. Department of Energy). Anadarko's U.S.
reserve replacement performance for the same period of 1997-2001 was 360% of
production or 195% of production, excluding mergers, acquisitions and
divestitures. Industry data for 2002 are not yet available.
COST OF FINDING Cost of finding represents the cost of proved reserves added
during a specific period through all means, including all costs and reserve
additions related to extensions and discoveries, revisions, improved recovery
and purchases of proved reserves. 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.
For the period 1998-2002, Anadarko's worldwide finding cost was $7.24 per
BOE. The Company's U.S. finding cost for the same five-year period was $7.78 per
BOE. Excluding mergers and acquisitions, Anadarko's worldwide and U.S. finding
costs for the five-year period 1998-2002 were $7.23 per BOE and $7.44 per BOE,
respectively. For the five-year period 1997-2001, Anadarko's worldwide finding
cost was $6.66 per BOE and its U.S. finding cost was $7.58 per BOE. For the
five-year period 1997-2001, the Company's worldwide and U.S. finding costs
excluding mergers and acquisitions were $5.88 per BOE and $6.78 per BOE,
respectively.
For 2002, Anadarko's worldwide finding cost was $10.52 per BOE. This
compares to $8.53 per BOE in 2001 and $7.19 per BOE in 2000. Anadarko's U.S.
finding cost for 2002 was $7.77 per BOE. This compares to $9.60 per BOE in 2001
and $8.49 per BOE in 2000. Excluding mergers and acquisitions, Anadarko's
worldwide finding cost for 2002 was $13.43 per BOE compared to $8.75 per BOE in
2001 and $5.83 per BOE in 2000. The Company's U.S. finding cost excluding
mergers and acquisitions for 2002 was $8.83 per BOE compared to $9.46 per BOE in
2001 and $6.77 per BOE in 2000. Worldwide finding costs in 2002 increased
compared to 2001 due primarily to downward revisions of Venezuelan reserves
primarily related to higher prices (see Critical Accounting Policies) and large
investments made in leases in the eastern Gulf of Mexico that have not yet been
drilled. Finding costs in 2001 were higher than 2000 due primarily to increases
in oilfield services costs and increased exploration and development activity.
PROVED RESERVES At the end of 2002 and 2001, Anadarko's proved reserves were
2.3 billion BOE compared to 2.1 billion BOE at year-end 2000. Anadarko's proved
reserves have grown 135% over the past three years, primarily as a result of
corporate acquisitions, successful exploration projects in the Gulf of Mexico
and successful development drilling programs in major domestic fields in core
areas onshore and offshore and in Algeria.
The Company's proved natural gas reserves at year-end 2002 were 7.2
trillion cubic feet (Tcf) compared to 7.0 Tcf at year-end 2001 and 6.1 Tcf at
year-end 2000. Anadarko's proved gas reserves have increased 186% since year-end
1999, as a result of corporate acquisitions, continued development activity
onshore in the U.S. and other producing property acquisitions. Anadarko's crude
oil, condensate and NGLs reserves at year-end 2002 were 1.1 billion barrels
compared to 1.1 billion barrels at year-end 2001 and 1.0 billion barrels at
year-end 2000. Crude oil reserves have risen by 97% over the last three years
primarily due to corporate acquisitions, successful exploration projects in the
Gulf of Mexico and successful development drilling programs in major domestic
fields in core areas onshore and offshore and in Algeria. Crude oil, condensate
and NGLs reserves comprise 49% of the Company's proved reserves at year-end 2002
and 2001 and 51% at year-end 2000.
At December 31, 2002, the present value (discounted at 10%) of future net
revenues from Anadarko's proved reserves was $21.1 billion, before income taxes,
and $14.1 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 increase of $6.1 billion or 76%
in 2002 compared to 2001 is primarily due to significantly higher natural gas
and higher crude oil prices at year-end 2002, additions of proved reserves
related to successful drilling worldwide and corporate acquisitions in 2002. See
Critical Accounting Policies and New Accounting Principles and Recent
Developments 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 asset acquisition and divestiture program. In 2002, Anadarko acquired approximately 87 MMBOE of proved reserves, including 74 MMBOE located in the United States primarily from the Howell Corporation (Howell) acquisition (64 MMBOE) and including 13 MMBOE located in Qatar. 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 Resources Canada Limited (Gulfstream) acquisition (57 MMBOE); and the United States (1 MMBOE). In 2000, Anadarko acquired with the Anadarko Holding merger transaction approximately 912 MMBOE of proved reserves, located primarily in the United States, Canada and Latin America. Excluding corporate acquisitions, during 2000-2002, Anadarko acquired through purchases and trades 38 MMBOE of proved reserves for $112 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, of 100 MMBOE with proceeds totaling $397 million. In 2003, the Company will continue to consider dispositions of certain producing properties in non-core areas.
PROPERTIES AND LEASES
PRODUCING PROPERTIES The Company owns 9,232 net producing gas wells and 7,011 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, 2002.
ACREAGE
DEVELOPED UNDEVELOPED TOTAL
------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
thousands ----- ----- ------ ------ ------ ------
United States
Onshore -- Lower 48 2,900 1,959 2,642 1,904 5,542 3,863
Offshore 441 204 1,486 1,129 1,927 1,333
Alaska 25 6 3,144 1,162 3,169 1,168
----- ----- ------ ------ ------ ------
Total 3,366 2,169 7,272 4,195 10,638 6,364
----- ----- ------ ------ ------ ------
Canada 1,811 1,024 9,357 3,343 11,168 4,367
Algeria* 219 54 3,775 1,167 3,994 1,221
Other International 570 155 24,896 10,435 25,466 10,590
|
LAND GRANT AND OTHER FEE MINERALS The Company also owns fee mineral interests on acreage totaling 10,159,000 (gross) or 9,101,000 (net) acres as of December 31, 2002. Of this amount, 7,933,000 (gross) or 7,741,000 (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 Anadarko Holding in the mid-1800s. The Company holds royalty interests of varying percentages throughout 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*
2002 2001 2000
millions ------ ------ ------
Development $1,079 $1,641 $ 921
Exploration 866 1,030 429
Acquisitions of producing properties 14 14 54
Gathering and other 78 244 80
Capitalized interest and internal costs related to
exploration
and development costs 351 387 224
------ ------ ------
Total $2,388 $3,316 $1,708
------ ------ ------
|
The Company's primary focus for 2002 was to find additional oil and gas
reserves and maintain Company-wide production. Anadarko's total capital spending
in 2002 was $2.4 billion, a 28% decrease compared to 2001. The decrease from
2001 represents a $562 million decrease in development spending, a $164 million
decrease in exploration and a $202 million decrease in gathering and other
spending. The decrease in spending for development activities reflects the
Company's decision to focus on increasing its inventory of drilling prospects by
identifying new reserves through exploration, rather than growing production
through development during the down cycle for energy prices earlier in the year.
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.
The Company funded its capital investment programs in 2002, 2001 and 2000
primarily through cash flow, plus increases in long-term debt, proceeds from
property sales and issuances of common stock.
Capital spending for 2003 has been initially set at $2.3 billion, which is
a slight decrease compared to 2002. The primary focus of the 2003 budget is to
find additional oil and gas reserves and develop existing fields. Anadarko has
allocated nearly $1.5 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 $380 million is
budgeted for exploration programs, mainly in western Canada, the Gulf of Mexico,
east Texas, north Louisiana and Alaska. About 70% of the exploration budget will
be for drilling compared to 53% in 2002. 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 2002, Anadarko's total debt was $5.5 billion. This compares to
total debt of $5.1 billion at year-end 2001 and $4.0 billion at year-end 2000.
The increases in debt are related primarily to the Howell acquisition in 2002
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. In March 2002, ZYP-CODES in the
amount of $620 million were put to the Company for repayment and were paid in
cash. Holders of the remaining ZYP-CODES have the right to require Anadarko to
purchase all or a portion of their ZYP-CODES in March 2004, 2006, 2011 or 2016,
at $1,000 per ZYP-CODES.
In February 2002, the Company issued $650 million principal amount of
5 3/8% Notes due 2007. In March 2002, the Company issued $400 million principal
amount of 6 1/8% Notes due 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.
In April 2002, Anadarko filed a shelf registration statement with the SEC
that permits the issuance of up to $1 billion in debt securities, preferred
stock, preferred securities, depositary shares, common stock, warrants, purchase
contracts and purchase units. Net proceeds, terms and pricing of the offerings
of securities issued under the shelf registration statement will be determined
at the time of the offerings.
In September 2002, Anadarko issued $300 million principal amount of 5%
Notes due 2012. The net proceeds from the issuance were used to reduce floating
rate debt. These notes were issued under the shelf registration statement filed
in April 2002.
In October 2002, the Company entered into a 364-Day Revolving Credit
Agreement. The agreement provides for $225 million principal amount and expires
in 2003. Also in October 2002, Anadarko Canada Corporation, a wholly owned
subsidiary of Anadarko, entered into a 364-Day Canadian Credit Agreement. The
agreement provides for $300 million principal amount and expires in 2003. The
Canadian agreement is fully and unconditionally guaranteed by Anadarko. In
addition, the Company has a Revolving Credit Agreement that provides for $225
million principal amount and expires in 2004. As of December 31, 2002, the
Company had no outstanding borrowings under these credit agreements.
PREFERRED STOCK During 2002 and 2001, Anadarko repurchased $2 million and $97 million of preferred stock, respectively.
COMMON STOCK PURCHASE PROGRAM In 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 2002 and 2001 in conjunction with the stock purchase program,
Anadarko sold put options to independent third parties. These put options
entitled 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. A put option for 1 million shares was exercised
and put options for 2 million shares expired unexercised in 2001. Put options
for the remaining 2 million shares expired unexercised in 2002. In 2002, the
Company entered into a put option for 1 million shares of Anadarko common stock
with a notional amount of $46 million. The Company received
premiums of $7 million during 2002. This put option expired unexercised in 2002.
The put options permitted a net-share settlement at the Company's option and did
not result in a liability on the consolidated balance sheet.
The following table summarizes purchases under the stock purchase program
and the effect of the related put option premiums on the repurchase price.
TOTAL
2002 2001 PROGRAM
millions, except per share amounts ------ ------ -------
Shares repurchased 1.0 2.2 3.2
Total paid for shares repurchased $ 50 $ 116 $ 166
Put premiums settled (14) (7) (21)
------ ------ ------
Total repurchase price $ 36 $ 109 $ 145
------ ------ ------
Average repurchase price per share $36.08 $49.41 $45.24
|
OBLIGATIONS AND COMMITMENTS
Following is a summary of the Company's future payments on obligations as of December 31, 2002.
OBLIGATIONS BY PERIOD
----------------------------------------
2-3 4-5 LATER
1 YEAR YEARS YEARS YEARS TOTAL
millions ------ ----- ----- ------ ------
Total debt* $300 $200 $912 $4,207 $5,619
Operating leases 72 122 105 208 507
Transportation and storage 5 39 28 124 196
Oil and gas activities -- 100 5 -- 105
|
SYNTHETIC LEASES Anadarko has two lease arrangements for its corporate office buildings in The Woodlands, Texas. The development and acquisition of the properties were financed by special purpose entities (SPEs) sponsored by a financial institution. The total amount funded under these leases was $213 million. In addition, the Company has a total lease payment obligation of $11 million related to aircraft operating leases financed by synthetic leases. The table above includes lease payment obligations related to these synthetic leases under operating leases. For additional information see Note 17 -- Commitments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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 previous table reflect obligations and commitments that are not included in the 2003 capital budget. Following is a description of the Company's significant operating obligations and commitments related to oil and gas activities.
Production Platform In April 2002, the Company signed an agreement under which a floating production platform for its Marco Polo discovery in Green Canyon Block 608 of the Gulf of Mexico will be installed. Since the Company's obligation related to the agreement begins at the time of project completion, the table above does not include any amounts related to this agreement. For additional information see Note 17 -- Commitments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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 $105 million, comprised of $37 million in the United States, $35 million in Canada, $24 million in Algeria and $9 million in other international locations. The commitments in Algeria are related primarily to exploration and development contracts with Sonatrach, who is the registered owner of 4.9% of the Company's outstanding common stock.
Sales Commitments In Canada, the Company has commitments to deliver gas under fixed price contracts. The gas volumes to be delivered under these contracts are as follows:
COMMITMENTS BY PERIOD
------------------------------
2-3 4-5
1 YEAR YEARS YEARS TOTAL
------ ----- ----- -----
NATURAL GAS
Volume -- million MMBtu 25 33 5 63
Price per MMBtu $2.01 $1.92 $1.69 $1.93
|
OTHER The Company has defined benefit pension plans and supplemental plans that are non-contributory pension plans. In January 2003, the Company made a $52 million contribution to a defined benefit pension plan.
For additional information on contracts and arrangements the Company enters
into from time to time see Note 7 -- Debt, Note 8 -- Financial Instruments, Note
18 -- Pension Plans, Other Postretirement Benefits and Employee Savings Plans
and Note 19 -- 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 2002 was $2.2 billion
compared to $3.3 billion in 2001 and $1.5 billion in 2000. The decrease in 2002
cash flow is attributed to a significant decrease in natural gas prices. The
Company's original capital expenditure budget for 2003 has been set at $2.3
billion and net cash from operating activities in 2003 is expected to be about
$2.6 billion. The Company plans to use a portion of 2003 cash flow to repay
about $300 million in debt. 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. The Company's cash flow and capital expenditure estimates
for 2003 were based on prices far below where oil and gas prices were trading in
the first quarter of 2003. If higher prices are realized, the Company may expand
the drilling program, make targeted acquisitions or further reduce debt. The
Company has a stock buyback program to purchase up to $1 billion in shares of
Anadarko common stock. Any stock repurchases for 2003 are not included in the
announced capital expenditure budget and are not currently anticipated.
Both exchange and over-the-counter traded financial derivative instruments
are subject to margin deposit requirements. Margin deposits are required by the
Company whenever its unrealized losses with a counterparty exceed pre-determined
credit limits. Given the Company's sizable hedge position and price volatility,
the Company may be required from time to time to advance cash to its
counterparties in order to satisfy these margin deposit requirements. During
January and February 2003, the Company's margin deposit requirements have ranged
from zero to $125 million. Based on NYMEX future strip prices, the Company's
margin deposit requirement was $25 million on March 7, 2003.
Anadarko believes that operating cash flow and existing or available credit
facilities will be adequate to meet its capital and operating requirements for
2003. The Company funds its day-to-day operating expenses and capital
expenditures from operating cash flows, supplemented as needed by short-term
borrowings under 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, possible redemption of convertible debt securities 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.
DIVIDENDS
In 2002, Anadarko paid $80 million in dividends to its common stockholders
(7.5 cents per share in the first, second and third quarters and 10 cents per
share in the fourth quarter). 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 the fourth quarter). The dividend amount in
2000 was $39 million (5 cents per share per quarter). Anadarko has paid a
dividend to its common stockholders continuously since becoming an independent
company in 1986.
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, 2002, 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, 2002. 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.
In 2002, 2001 and 2000, the Company also paid $6 million, $7 million and
$11 million, respectively, in preferred stock dividends. In 2003, the preferred
stock dividends are expected to be $5 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 (generally 20% to 50% owned) using the equity method of accounting. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. 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. On an ongoing basis, Management reviews its estimates, including those related to litigation, environmental liabilities, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and 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. 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
country. The application of the full cost method of accounting for oil and gas
properties generally results in higher capitalized costs and higher DD&A rates
compared to the successful efforts method of accounting for oil and gas
properties.
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 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, as defined by SEC Regulation S-X Rule 4-10(a) (2i), (2ii), (2iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Prices do not include the effect of derivative instruments entered into by the Company.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery are included as proved
developed reserves only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units are claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation.
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.
Under the terms of Anadarko's risk service contract with the national oil
company of Venezuela, Anadarko earns a fee that is translated into barrels of
oil based on current prices (economic interest method). This means that higher
oil prices reduce the Company's reported production volumes and reserves from
that project and lower oil prices increase reported production volumes and
reserves. Production volume and reserve changes due to the prices used to
determine the Company's economic interest have no impact on the value of the
project. The following table shows the impact on 2002 at various price levels to
demonstrate the effect of the economic interest method.
ECONOMIC INTEREST METHOD
--------------------------
NYMEX price per barrel $36.00 $30.00 $24.00
Revenues -- millions $ 88 $ 88 $ 88
Production volumes -- MMBOE 3 4 5
Reserves -- MMBOE 65 78 98
|
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. The amount of 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 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, relinquishing drilling rights
or other information. 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 Company has a 10
to 15 year exploration and evaluation program for the Land Grant acreage. Costs
will be transferred accordingly to the DD&A pool over the length of the program.
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
transferred to the DD&A pool over a three- to five- year period based on the
average lease period. Exploration costs are transferred to the DD&A pool upon
completion of evaluation.
CAPITALIZED INTEREST SFAS No. 34, "Capitalization of Interest Cost," provides standards for the capitalization of interest cost as part of the historical cost of acquiring assets. Under FASB-Interpretation (FIN) No. 33 "Applying FASB Statement No. 34 to Oil and Gas Producing Operations Accounted for by the Full Cost Method," 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 qualifying 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 SEC Regulation S-X Rule 4-10. 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 reserve estimates, which are determined by the Company's engineers, are
reviewed and revised as reservoir performance, prices and other 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 2002, Anadarko's ceiling tests were based on NYMEX prices of $4.60 per
Mcf for natural gas and $31.20 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 related to oil and gas activities 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 INSTRUMENTS Anadarko uses derivative instruments for various risk
management purposes. Effective January 2001, derivative 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 Hedging Activities." Under this statement, all
derivatives are carried on the balance sheet at fair value. Realized gains and
losses are recognized in sales when the underlying physical gas and oil
production is sold. Accordingly, realized derivative gains and losses are
generally offset by similar changes in the realized value of the underlying
physical gas and oil production. Realized derivative gains and losses are
reflected in the average sales price of the physical gas and oil production.
Accounting for unrealized gains and losses is dependent on whether the
derivative instruments have been designated and qualify as part of a hedging
relationship. Derivative instruments may be designated as a hedge of exposure to
changes in fair values, cash flows or foreign currencies, if certain conditions
are met. Unrealized gains and losses on derivative instruments that do not meet
the conditions to qualify for hedge accounting are recognized currently in other
(income) expense.
If the hedged exposure is to changes in fair value, the gains and losses on
the derivative instrument, as well as the offsetting losses and gains on the
hedged item, are recognized currently in earnings. Consequently, if gains and
losses on the derivative 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 and losses on the derivative 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 and losses from the derivative
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.
Derivative 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 Instruments under Item 7a of this Form
10-K) were accounted for under the mark-to-market accounting method pursuant to
EITF Issue No. 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 unrealized gains
and losses are recorded in the statement of income and carried as assets or
liabilities on the balance sheet. EITF Issue No. 98-10 was rescinded in October
2002. As a result, mark-to-market accounting is precluded for energy trading
contracts that are not derivatives pursuant to SFAS No. 133. The recission of
EITF Issue No. 98-10 is effective for contracts entered into after October 25,
2002 and is effective for all contracts January 1, 2003. Substantially all of
the Company's physical delivery energy trading contracts are considered to be
derivatives pursuant to SFAS No. 133. Therefore, the recission of EITF Issue No.
98-10 did not have a significant impact on the accounting for energy trading
contracts as those contracts continue to be marked-to-market in accordance with
SFAS No. 133.
The Company's derivative 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 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 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 AND RECENT DEVELOPMENTS
New Accounting Principles For information on New Accounting Principles see Note
1 -- Summary of Significant Accounting Policies of the Notes to Consolidated
Financial Statements under Item 8 of this Form 10-K.
Proved Reserves The SEC is currently in the process of obtaining information
from oil and gas exploration companies operating offshore (including Anadarko)
to assess the criteria being used by industry to determine proved reserves
related to new field discoveries offshore. The SEC regulations allow companies
to recognize proved reserves if economic producibility is supported by either an
actual production test (flow test) or conclusive formation testing. In the
absence of a production test, compelling technical data must exist to recognize
proved reserves related to the initial discovery of a field. In deep-water
environments where production tests are extremely expensive, the industry has
increasingly depended on advanced technical testing to support economic
producibility.
Anadarko has recorded proved reserves related to the initial discovery of
four offshore fields based on conclusive formation tests rather than actual
production tests. As of December 31, 2002, these proved reserves amounted to 100
MMBOE or less than 5% of Anadarko's total worldwide proved reserves. The Company
is currently developing all of these fields and expects the majority of the
production from these fields to commence during 2004. Anadarko believes the
reserves were properly classified.
Most of these reserves are located at Marco Polo, a deep-water field under
development at Green Canyon Block 608. Ryder Scott Company, an independent
petroleum consulting company, has reviewed Anadarko's technical data and studies
used to support the classification of proved reserves at the Marco Polo field.
Ryder Scott's review concludes that the reserves meet the SEC's definition of
proved reserves. A copy of the Ryder Scott report is attached as Exhibit 99.3 to
this Form 10-K.
Anadarko has furnished the information requested to the SEC and is unable
to predict the likely outcome of the SEC's staff review of this industry
practice. The issue is not expected to have a material impact on the Company's
proved reserves or financial results; however, if the issue is not favorably
resolved, Anadarko may be required to revise its proved reserve estimates, which
would affect Anadarko's finding costs per barrel, reserve replacement ratios and
DD&A expense, until flow tests are conducted or production commences.
REGULATORY MATTERS AND ADDITIONAL FACTORS AFFECTING BUSINESS
FORWARD LOOKING STATEMENTS 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 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 19 -- 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 insured against all risks in
all aspects of its business, such as political risk, business interruption risk
and risk of major terrorist attacks, 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, 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 Anadarko Holding 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
DERIVATIVE INSTRUMENTS Anadarko's commodity derivative instruments currently
are comprised of futures, swaps and options contracts. The volume of commodity
derivative 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 risk management policy guidelines. For information
regarding the Company's accounting policies related to derivatives and
additional information related to the Company's derivative instruments, see Note
1 -- Summary of Significant Accounting Policies and Note 8 -- Financial
Instruments of the Notes to Consolidated Financial Statements under Item 8 of
this Form 10-K.
Derivative Instruments Held for Non-Trading Purposes The Company had equity production hedges of 334 billion cubic feet of natural gas and 28 million barrels of crude oil as of December 31, 2002. As of December 31, 2002, the Company had a net unrealized loss of $154 million before taxes on these commodity derivative instruments. Based upon an analysis utilizing the actual derivative contractual volumes, a 10% increase in commodity prices would result in an additional loss on these commodity derivative instruments of approximately $166 million. However, this loss would be substantially offset by a gain in the value of that portion of the Company's equity production that is hedged.
Derivative Instruments Held for Trading Purposes As of December 31, 2002, the Company had a net unrealized gain of $24 million (gains of $73 million and losses of $49 million) on commodity derivative instruments entered into for trading purposes and a net unrealized loss of $30 million (gains of $16 million and losses of $46 million) on physical contracts entered into for trading purposes. Based upon an analysis utilizing the actual derivative contractual volumes and assuming a 10% decrease in underlying commodity prices, the potential additional loss on the derivative instruments would be approximately $20 million.
Firm Transportation Keep-Whole Agreement Anadarko Holding Company (Anadarko
Holding) was a party to several long-term firm gas transportation agreements
that supported its gas marketing program within its gathering, processing and
marketing (GPM) business segment, which was sold in 1999 to Duke Energy (Duke).
As part of the GPM disposition, Anadarko Holding agreed to pay Duke if
transportation market values fall below the fixed contract transportation rates,
while Duke will pay Anadarko Holding if the transportation market values exceed
the contract transportation rates (keep-whole agreement). 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 instruments to
reduce its exposure under the keep-whole agreement to potential decreases in
future transportation market values. Due to decreased liquidity, the use of
derivative instruments to manage this risk is generally limited to the forward
twelve months. As of December 31, 2002, accounts payable included $5 million and
other long-term liabilities included $68 million related to this agreement. As
of December 31, 2001, accounts payable included $27 million and other long-term
liabilities included $80 million related to this agreement. A 10% unfavorable
change in prices on the short-term portion of the keep-whole agreement would
result in an additional loss of $10 million. The future gain or loss from this
agreement cannot be accurately predicted. For additional information related to
the keep-whole agreement, see Note 8 -- Financial Instruments of the Notes to
Consolidated Financial Statements under Item 8 of this Form 10-K.
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.
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 primarily in the United States, Canada and Argentina exceeded the ceiling limitation and the Company recorded a $2.5 billion ($1.6 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.
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.
At December 31, 2002 and 2001, a Canadian subsidiary had $98 million and
$187 million, respectively, outstanding of fixed-rate notes and debentures
denominated in U.S. dollars. The potential foreign currency remeasurement impact
on earnings from a 10% increase in the December 31, 2002 Canadian exchange rate
would be about $9 million based on the outstanding debt at December 31, 2002.
At December 31, 2002 and 2001, the Company's Latin American subsidiaries
had foreign deferred tax liabilities denominated in the local currency
equivalent totaling $49 million and $78 million, respectively. In conjunction
with the sale of certain properties in 2001, the Company indemnified a purchaser
for the use of local tax losses denominated in the local currency equivalent
totaling $22 million. The potential foreign currency remeasurement impact on net
earnings from a 10% increase in the year-end Latin American exchange rates would
be approximately $4 million.
For additional information related to foreign currency risk see Note 8 --
Financial Instruments of the Notes to Consolidated Financial Statements under
Item 8 of this Form 10-K.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANADARKO PETROLEUM CORPORATION
INDEX
CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Management 54
Independent Auditors' Report 55
Statements of Income, Three Years Ended December 31, 2002 56
Balance Sheets, December 31, 2002 and 2001 57
Statements of Stockholders' Equity, Three Years Ended
December 31, 2002 58
Statements of Comprehensive Income, Three Years Ended
December 31, 2002 59
Statements of Cash Flows, Three Years Ended December 31,
2002 60
Notes to Consolidated Financial Statements 61
Supplemental Information on Oil and Gas Exploration and
Production Activities 98
Supplemental Quarterly Information 111
|
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 accounting principles generally accepted in the United States
of America. 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 independent. 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.
/s/ JOHN N. SEITZ John N. Seitz President and Chief Executive Officer /s/ MICHAEL E. ROSE Michael E. Rose Executive Vice President and Chief Financial Officer |
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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2002, 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, 2002, the Company changed its method of accounting for goodwill,
effective January 1, 2001, the Company changed its method of accounting for
derivative 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, 2003 |
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31
--------------------------
2002 2001 2000
millions except per share amounts ------ ------ ------
REVENUES
Gas sales $1,835 $2,952 $1,615
Oil and condensate sales 1,690 1,397 946
Natural gas liquids sales 222 256 264
Other sales 113 113 86
------ ------ ------
Total 3,860 4,718 2,911
------ ------ ------
COSTS AND EXPENSES
Operating expenses 747 769 487
Administrative and general 314 292 270
Depreciation, depletion and amortization 1,121 1,154 593
Other taxes 214 247 128
Impairments related to oil and gas properties 39 2,546 50
Amortization of goodwill -- 73 31
------ ------ ------
Total 2,435 5,081 1,559
------ ------ ------
Operating Income (Loss) 1,425 (363) 1,352
OTHER (INCOME) EXPENSE
Interest expense 203 92 93
Other (income) expense 15 (65) (167)
------ ------ ------
Total 218 27 (74)
------ ------ ------
Income (Loss) Before Income Taxes 1,207 (390) 1,426
INCOME TAX EXPENSE (BENEFIT) 376 (214) 602
------ ------ ------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE $ 831 $ (176) $ 824
------ ------ ------
Preferred Stock Dividends 6 7 11
------ ------ ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 825 $ (183) $ 813
------ ------ ------
Cumulative Effect of Change in Accounting Principle -- 5 17
------ ------ ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ 825 $ (188) $ 796
------ ------ ------
PER COMMON SHARE
Net income (loss) -- before change in accounting
principle -- basic $ 3.32 $(0.73) $ 4.42
Net income (loss) -- before change in accounting
principle -- diluted $ 3.21 $(0.73) $ 4.25
Change in accounting principle -- basic $ -- $(0.02) $(0.09)
Change in accounting principle -- diluted $ -- $(0.02) $(0.09)
Net income (loss) -- basic $ 3.32 $(0.75) $ 4.32
Net income (loss) -- diluted $ 3.21 $(0.75) $ 4.16
Dividends $0.325 $0.225 $ 0.20
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -- BASIC 248 250 184
------ ------ ------
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -- DILUTED 260 250 193
------ ------ ------
|
See accompanying notes to consolidated financial statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
-----------------
2002 2001
millions ------- -------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 34 $ 37
Accounts receivable, net of allowance:
Customers 673 532
Others 435 486
Other current assets 138 146
------- -------
Total 1,280 1,201
------- -------
PROPERTIES AND EQUIPMENT
Original cost (includes unproved properties of $3,085 and
$3,573 as of December 31, 2002 and 2001, respectively) 22,595 20,088
Less accumulated depreciation, depletion and amortization 7,497 6,451
------- -------
Net properties and equipment -- based on the full cost
method of accounting for oil and gas properties 15,098 13,637
------- -------
OTHER ASSETS 436 503
------- -------
GOODWILL 1,434 1,430
------- -------
TOTAL ASSETS $18,248 $16,771
------- -------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,050 $ 1,132
Accrued expenses 511 257
Current portion, notes and debentures 300 412
------- -------
Total 1,861 1,801
------- -------
LONG-TERM DEBT 5,171 4,638
------- -------
OTHER LONG-TERM LIABILITIES
Deferred income taxes 3,633 3,451
Other 611 516
------- -------
Total 4,244 3,967
------- -------
STOCKHOLDERS' EQUITY
Preferred stock, par value $1.00 per share
(2.0 million shares authorized, 0.1 million shares issued
as of December 31, 2002 and 2001) 101 103
Common stock, par value $0.10 per share
(450.0 million shares authorized, 254.6 million and 254.1
million shares issued as of December 31, 2002 and 2001,
respectively) 25 25
Paid-in capital 5,347 5,336
Retained earnings 2,021 1,276
Treasury stock (3.2 million and 2.2 million shares as of
December 31, 2002 and 2001, respectively) (166) (116)
Deferred compensation and ESOP (0.7 million and 0.9 million
shares as of December 31, 2002 and 2001, respectively) (63) (96)
Executives and Directors Benefits Trust, at market value
(2.0 million shares as of December 31, 2002 and 2001) (95) (114)
Accumulated other comprehensive loss
Unrealized loss on derivative instruments (85) --
Foreign currency translation adjustments (37) (46)
Minimum pension liability (76) (3)
------- -------
Total (198) (49)
------- -------
Total 6,972 6,365
------- -------
COMMITMENTS AND CONTINGENCIES -- --
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $18,248 $16,771
------- -------
|
See accompanying notes to consolidated financial statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31
--------------------------
2002 2001 2000
millions ------ ------ ------
PREFERRED STOCK
Balance at beginning of year $ 103 $ 200 $ 200
Preferred stock repurchased (2) (97) --
------ ------ ------
Balance at end of year 101 103 200
------ ------ ------
COMMON STOCK
Balance at beginning of year 25 25 13
Common stock issued -- -- 12
------ ------ ------
Balance at end of year 25 25 25
------ ------ ------
PAID-IN CAPITAL
Balance at beginning of year 5,336 5,303 634
Common stock and common stock put options issued 30 51 4,592
Revaluation to market for Executives and Directors Benefits
Trust (19) (31) 77
Preferred stock repurchased -- 13 --
------ ------ ------
Balance at end of year 5,347 5,336 5,303
------ ------ ------
RETAINED EARNINGS
Balance at beginning of year 1,276 1,521 764
Net income (loss) 831 (181) 807
Dividends paid -- preferred (6) (7) (11)
Dividends paid -- common (80) (57) (39)
------ ------ ------
Balance at end of year 2,021 1,276 1,521
------ ------ ------
TREASURY STOCK
Balance at beginning of year (116) -- --
Purchase of treasury stock (50) (116) --
------ ------ ------
Balance at end of year (166) (116) --
------ ------ ------
DEFERRED COMPENSATION AND ESOP
Balance at beginning of year (96) (121) (8)
Issuance of restricted stock (7) (15) (82)
Acquisition of ESOP -- -- (74)
Amortization of restricted stock and release of ESOP shares 40 40 43
------ ------ ------
Balance at end of year (63) (96) (121)
------ ------ ------
EXECUTIVES AND DIRECTORS BENEFITS TRUST
Balance at beginning of year (114) (145) (68)
Revaluation to market 19 31 (77)
------ ------ ------
Balance at end of year (95) (114) (145)
------ ------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year (49) 3 --
Unrealized loss on derivative instruments (85) -- --
Foreign currency translation adjustments 9 (49) 3
Minimum pension liability (73) (3) --
------ ------ ------
Balance at end of year (198) (49) 3
------ ------ ------
TOTAL STOCKHOLDERS' EQUITY $6,972 $6,365 $6,786
------ ------ ------
|
See accompanying notes to consolidated financial statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31
------------------------
2002 2001 2000
millions ----- ----- ----
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ 825 $(188) $796
Add: Preferred Stock Dividends 6 7 11
----- ----- ----
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS BEFORE
PREFERRED STOCK DIVIDENDS 831 (181) 807
----- ----- ----
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Unrealized gain (loss) on derivative instruments:
Cumulative effect of accounting change(1) -- (5) --
Reclassification of cumulative effect of accounting change
included in net income(2) -- 4 --
Unrealized gain (loss) during the period(3) (100) 32 --
Reclassification adjustment for (gain) loss included in
net income(4) 15 (31) --
----- ----- ----
Total unrealized loss on derivative instruments (85) -- --
Foreign currency translation adjustments 9 (49) 3
Minimum pension liability(5) (73) (3) --
----- ----- ----
Total (149) (52) 3
----- ----- ----
COMPREHENSIVE INCOME (LOSS) $ 682 $(233) $810
----- ----- ----
|
(1)net of income tax benefit (expense) of: $ -- $ 3 $ -- (2)net of income tax benefit (expense) of: -- (2) -- (3)net of income tax benefit (expense) of: 58 (19) -- (4)net of income tax benefit (expense) of: (9) 18 -- (5)net of income tax benefit (expense) of: 42 1 -- |
See accompanying notes to consolidated financial statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
---------------------------
2002 2001 2000
millions ------- ------- -------
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) before cumulative effect of change in
accounting principle $ 831 $ (176) $ 824
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 1,134 1,170 627
Amortization of goodwill -- 73 31
Interest expense -- zero coupon debentures 13 13 10
Deferred income taxes 214 (319) 457
Impairments related to oil and gas properties 39 2,546 50
Other non-cash items (19) 122 (124)
------- ------- -------
2,212 3,429 1,875
(Increase) decrease in accounts receivable (103) 544 (703)
Increase (decrease) in accounts payable and accrued expenses 181 (534) 415
Other items -- net (94) (118) (51)
------- ------- -------
Net cash provided by operating activities 2,196 3,321 1,536
------- ------- -------
CASH FLOW FROM INVESTING ACTIVITIES
Additions to properties and equipment (2,388) (3,316) (1,708)
Acquisition costs, net of cash acquired (221) (940) (53)
Sales and retirements of properties and equipment 192 138 61
------- ------- -------
Net cash used in investing activities (2,417) (4,118) (1,700)
------- ------- -------
CASH FLOW FROM FINANCING ACTIVITIES
Additions to debt 1,348 2,788 345
Retirements of debt (987) (1,977) (321)
Increase (decrease) in accounts payable, banks (43) 24 56
Dividends paid (86) (64) (50)
Retirement of preferred stock (2) (84) --
Purchase of treasury stock (50) (116) --
Issuance of common stock and common stock put options 40 49 288
------- ------- -------
Net cash provided by financing activities 220 620 318
------- ------- -------
EFFECT OF EXCHANGE RATE CHANGES ON CASH (2) 15 --
------- ------- -------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (3) (162) 154
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 37 199 45
------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 34 $ 37 $ 199
------- ------- -------
|
See accompanying notes to consolidated financial statements.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT 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.
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 (generally 20% to 50% owned) using the equity method of accounting. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. Certain amounts for prior periods 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. On an ongoing basis, Management reviews its estimates, including those related to litigation, environmental liabilities, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
CHANGES IN ACCOUNTING PRINCIPLES During 2002, the Company adopted Emerging
Issues Task Force (EITF) Issue No. 02-3, "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities." In accordance with EITF Issue No. 02-3,
marketing sales and purchases resulting in physical settlement for prior periods
have been reclassified to show net marketing margins as revenues. The marketing
margins related to the Company's equity production are included in gas sales,
oil and condensate sales and natural gas liquids sales and are reflected in
commodity prices. The marketing margin related to purchases of third-party
commodities is included in other sales. This reclassification had no effect on
reported net income or cash flow.
In 2002, the Company discontinued the amortization of goodwill in
accordance with Statement of Financial Accounting Standards (SFAS) No. 142,
"Goodwill and Other Intangible Assets." See Note 3.
In 2002, the Company adopted the disclosure provisions of SFAS No. 148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure." See Note
2.
In 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which provides guidance for accounting for
derivative instruments and hedging activities. 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) in 2001.
In 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
country.
The sum of net capitalized costs and estimated future development and
abandonment costs of oil and gas properties and mineral investments are
amortized using the unit-of-production method. All other properties are
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
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. The amount of 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, relinquishing drilling rights or other information. 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 Company has a 10
to 15 year exploration and evaluation program for the Land Grant acreage. Costs
will be transferred accordingly to the DD&A pool over the length of the program.
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
transferred to the DD&A pool over a three- to five-year period based on the
average lease period. Exploration costs are transferred to the DD&A pool upon
completion of evaluation.
CAPITALIZED INTEREST SFAS No. 34, "Capitalization of Interest Cost," provides standards for the capitalization of interest cost as part of the historical cost of acquiring assets. Under Financial Accounting Standards Board Interpretation (FIN) No. 33, "Applying FASB Statement No. 34 to Oil and Gas Producing Operations Accounted for by the Full Cost Method," 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 qualifying 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 Under the full cost method of accounting, a ceiling test is
performed each quarter. The full cost ceiling test is an impairment test
prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit,
on a country-by-country basis, on the book value of oil and gas properties. The
capitalized costs of proved oil and gas properties, net of accumulated DD&A and
the related deferred income taxes, may not exceed 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, as defined by SEC Regulation S-X Rule
4-10(a)(2i), (2ii), (2iii), (3) and (4), are the estimated quantities of crude
oil, natural gas, and NGLs which geological and engineering data demonstrate
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions. Prices do not include the effect of
derivative instruments entered into by the Company.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery are included as proved
developed reserves only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
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.
REVENUES The Company recognizes sales revenues based on the amount of gas, oil and NGLs sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred. The Company follows the sales method of accounting for production imbalances. If the Company's excess sales of production volumes for a well exceed the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which the Company has taken less than its ownership share of production. Marketing margins related to the Company's equity production are included in gas sales, oil and condensate sales and natural gas liquids sales and are reflected in commodity prices. The marketing margin related to purchases of third-party commodities is included in other sales.
DERIVATIVE INSTRUMENTS Anadarko uses derivative instruments for various risk
management purposes. Effective January 2001, derivative instruments utilized to
manage or reduce commodity price risk related to the Company's equity production
are 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
and losses are recognized in sales when the underlying physical gas and oil
production is sold. Accordingly, realized derivative gains and losses are
generally offset by similar changes in the realized value of the underlying
physical gas and oil production. Realized derivative gains and losses are
reflected in the average sales price of the physical gas and oil production.
Accounting for unrealized gains and losses is dependent on whether the
derivative instruments have been designated and qualify as part of a hedging
relationship. Derivative instruments may be designated as a hedge of exposure to
changes in fair values, cash flows or foreign currencies, if certain conditions
are met. Unrealized gains and losses on derivative instruments that do not meet
the conditions to qualify for hedge accounting are recognized currently in other
(income) expense.
If the hedged exposure is to change in fair value, the gains and losses on
the derivative instrument, as well as the offsetting losses and gains on the
hedged item, are recognized currently in earnings. Consequently, if gains and
losses on the derivative instrument and the related hedge item do not completely
offset, the difference (i.e., ineffective portion of the hedge) is recognized
currently in earnings.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
If the hedged exposure is a cash flow exposure, the effective portion of
the gains and losses on the derivative 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 and losses from the derivative
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.
Derivative 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 were accounted for under the mark-to-market accounting
method pursuant to EITF Issue No. 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 unrealized gains and losses are recorded in the statement of income
and carried as assets or liabilities on the balance sheet. EITF Issue No. 98-10
was rescinded in October 2002. See New Accounting Principles.
The Company's derivative 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 quoted natural gas basis prices, while the fair
value of the long-term portion is estimated based on historical natural gas
basis prices, discounted at 10% per year. See Note 8.
Prior to 2001, derivative 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 and losses and option
premiums were recognized in the statement of income when the underlying physical
oil and gas production was sold. Accordingly, realized gains and losses were
generally offset by similar changes in the realized prices of the underlying
physical oil and gas production. Realized derivative gains and losses were
reflected in the average sales price of the physical oil and gas production.
Margin deposits, deferred realized gains and losses and premiums were included
in other current assets or liabilities. Unrealized gains and losses were not
recorded.
INVENTORIES Materials and supplies and company-produced commodity inventories are stated at the lower of average cost or market. Prior to October 25, 2002, inventories consisting of commodities purchased from third parties utilized in the Company's energy trading activities were carried at fair value. Company-produced commodities, when sold from inventory, were charged to expense using the average-cost method. Commodities purchased from third parties, when sold from inventory, were charged to expense using market price. Due to the recission of EITF Issue No. 98-10, commodities purchased from third parties after October 25, 2002 are accounted for at the lower of average-cost or market. See New Accounting Principles.
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 Anadarko Holding Company (Anadarko Holding), and the acquisition of Berkley Petroleum Corp. (Berkley). For 2000 and 2001, goodwill was amortized on a straight-line basis over 20 years. Prior to the adoption of SFAS No. 142, 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 operations. 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. In accordance with the adoption of SFAS No. 142, the Company assesses the carrying amount of goodwill by testing the goodwill for impairment. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit 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 the
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
goodwill is written down to the implied fair value of the goodwill through a charge to expense. Also under SFAS No. 142, goodwill is no longer amortized effective January 2002. See Note 3.
LEGAL CONTINGENCIES The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. See Note 19.
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. See Note 19.
INCOME TAXES The Company files various United States federal, state and foreign income tax returns. Deferred federal, state and foreign income taxes are provided on all significant temporary differences, except for those 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. See Notes 2 and 10.
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, if including such equity instruments is dilutive. 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 including such potential common shares is dilutive. See Note 10.
NEW ACCOUNTING PRINCIPLES 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 is effective for the Company in 2003. The Company has evaluated the impact
of SFAS No. 143 and expects to record an after tax gain of between $35 million
and $55 million as a cumulative effect of change in accounting principle.
Additionally, the Company expects to record an asset retirement obligation
liability of between $220 million and $330 million and an increase to net
properties and equipment of between $270 million and $410 million. The
application of SFAS No. 143 in 2003 and future years will result in the
recognition of accretion expense related to the discounted liability for the
asset retirement obligation and should not have a material impact on the
Company's DD&A rate. There will be no impact on the Company's cash flow as a
result of adopting SFAS No. 143.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64," was issued
in April 2002. SFAS No. 145 provides guidance for income statement
classification of gains and losses on extinguishment of debt and accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
transactions. SFAS No. 145 is effective for the Company in 2003. The Company has
evaluated the impact of SFAS No. 145 and does not expect adoption to materially
affect the consolidated financial statements.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in June 2002. SFAS No. 146 addresses significant issues
regarding the recognition, measurement and reporting of costs that are
associated with exit and disposal activities, including restructuring
activities. SFAS No. 146 is effective for the Company in 2003. The Company has
evaluated the impact of SFAS No. 146 and does not expect adoption to materially
affect the consolidated financial statements.
SFAS No. 148 was issued in December 2002. SFAS No. 148 provides alternative
methods of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation and amends the disclosure
requirements of SFAS No. 123, "Accounting for Stock-Based Compensation." The
Company adopted the disclosure provisions in 2002 and plans to voluntarily
change in 2003 to the fair value based method of accounting for stock-based
employee compensation using the prospective method described in SFAS No. 148.
EITF Issue No. 98-10 was rescinded in 2002. As a result, mark-to-market
accounting is precluded for commodity inventories and energy trading contracts
that are not derivatives pursuant to SFAS No. 133. The recission of EITF Issue
No. 98-10 is effective for commodity inventories acquired and contracts entered
into subsequent to October 25, 2002 and for all commodity inventories held and
contracts in effect on January 1, 2003. Substantially all of the Company's
physical delivery energy trading contracts are considered to be derivatives
pursuant to SFAS No. 133. Therefore, the recission of EITF Issue No. 98-10 did
not have a significant impact on the accounting for energy trading contracts as
those contracts continue to be marked to market in accordance with SFAS No. 133.
FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees," was issued in November 2002. This interpretation addresses the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under guarantees. It also clarifies the
requirements related to the recognition of a liability by a guarantor at the
inception of a guarantee for the obligations the guarantor has undertaken in
issuing that guarantee. The Company has adopted the disclosure provisions in
2002. See Notes 17 and 19. The initial recognition and initial measurement
provisions are applicable to guarantees issued or modified in 2003 and are not
expected to have a material impact on the Company's consolidated financial
statements.
FIN No. 46, "Consolidation of Variable Interest Entities," was issued in
January 2003. FIN No. 46 addresses consolidation by business enterprises of
variable interest entities. It applies immediately to variable interest entities
created after January 31, 2003. For entities created prior to this date, FIN No.
46 is effective for the third quarter 2003. The Company is evaluating the impact
of FIN No. 46 on accounting for and the possible restructuring of its synthetic
leases. See Note 17. If the synthetic leases are not restructured prior to July
2003, the current synthetic lease related entities will be consolidated with the
Company. The Company believes this would increase properties and equipment by
$220 million with a corresponding increase in long-term debt of $232 million.
Any impact on the income statement would be a cumulative effect adjustment equal
to the difference between the fair value of the assets and liabilities recorded
related to the consolidated variable interest entities and is not expected to be
material.
2. STOCK-BASED COMPENSATION
SFAS No. 123 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. Anadarko applies APB No. 25 in accounting for employee stock compensation plans whereby 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
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
2. STOCK-BASED COMPENSATION (CONTINUED)
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:
2002 2001 2000
millions except per share amounts ----- ------ -----
Net income (loss) available to common stockholders
before cumulative effect of change in accounting principle $ 825 $ (183) $ 813
Add: Stock-based employee compensation expense included in
net income, after taxes 9 10 21
Deduct: Total stock-based employee compensation expense
determined under the fair value method, after taxes (32) (52) (58)
----- ------ -----
Pro forma net income (loss) $ 802 $ (225) $ 776
----- ------ -----
Basic EPS - as reported $3.32 $(0.73) $4.42
Basic EPS - pro forma $3.23 $(0.90) $4.22
Diluted EPS - as reported $3.21 $(0.73) $4.25
Diluted EPS - pro forma $3.13 $(0.90) $4.05
|
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:
2002 2001 2000
----- ----- -----
Expected option life - years 5.29 4.14 4.35
Risk-free interest rate 3.73% 4.48% 6.10%
Dividend yield 0.51% 0.46% 0.50%
Volatility 41.66% 43.79% 39.17%
|
3. GOODWILL
SFAS No. 142 required 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.
In January 2002, the Company discontinued the amortization of goodwill in
accordance with SFAS No. 142. The transitional goodwill impairment test as of
January 2002 was performed and no goodwill impairment was indicated. The annual
goodwill impairment test was performed as of January 2003 and no goodwill
impairment was indicated. The following table shows the effect of the
elimination of amortization of goodwill on the
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
3. GOODWILL (CONTINUED)
Company's net income and net income per share as if SFAS No. 142 had been in effect in prior periods. Prior to 2000, the Company had no goodwill or goodwill amortization recorded.
2001 2000
millions except per share amounts ------ -----
Net income (loss) $ (188) $ 796
Add: Goodwill amortization 73 31
------ -----
Adjusted net income (loss) $ (115) $ 827
------ -----
Earnings (loss) per share -- basic $(0.75) $4.32
Goodwill amortization per share -- basic 0.29 0.17
------ -----
Adjusted earnings (loss) per share -- basic $(0.46) $4.49
------ -----
Earnings (loss) per share -- diluted $(0.75) $4.16
Goodwill amortization per share -- diluted 0.29 0.16
------ -----
Adjusted earnings (loss) per share -- diluted $(0.46) $4.32
------ -----
|
The changes in goodwill since December 31, 2001 are due primarily to changes in foreign currency exchange rates. Future changes in goodwill may result from, among other things, changes in foreign currency exchange rates, changes in deferred income tax liabilities related to acquisitions, divestitures, impairments or future acquisitions.
4. MERGER AND ACQUISITIONS
In July 2000, the Company merged with Union Pacific Resources Group Inc.,
subsequently renamed Anadarko Holding Company. Each share of common stock of
Anadarko Holding issued and outstanding was converted into 0.455 shares of
Anadarko common stock. The merger was 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 Anadarko Holding were recorded at their estimated fair market
values.
Had the Anadarko Holding merger transaction occurred on January 1, 2000,
unaudited pro forma results of the Company would have included revenues of $4.1
billion and net income available to common stockholders of $1.1 billion ($4.45
per share -- basic and $4.30 per share -- diluted) for the year ended December
31, 2000. The pro forma results for 2000 are a result of combining the statement
of income of Anadarko with the statement of income of Anadarko Holding adjusted
for (1) certain costs that Anadarko Holding had expensed under the successful
efforts method of accounting that are capitalized under the full cost method of
accounting; (2) DD&A expense of Anadarko Holding calculated in accordance with
the full cost method of accounting applied to the 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 Anadarko Holding 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 and are not necessarily
indicative of actual results.
In March 2001, Anadarko acquired Canadian based Berkley for C$11.40 per
share for an aggregate equity value of $779 million plus the assumption of $236
million of debt. Goodwill recorded related to the Berkley acquisition was $245
million.
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 $118 million plus the assumption of $10
million of debt.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
4. MERGER AND ACQUISITIONS (CONTINUED)
In December 2002, the Company completed the acquisition of Howell
Corporation (Howell) in which the common stockholders of Howell received $20.75
per share and holders of Howell's $3.50 convertible preferred stock received
$76.15 per share. The value of the acquisition was $258 million, including the
assumption of $53 million of debt.
The unaudited pro forma results of operations including the acquisition
transactions in 2002 and 2001 would not have been significantly different from
actual results for 2002 and 2001.
Merger costs related to corporate acquisitions of $14 million, $45 million
and $67 million for the years ended December 31, 2002, 2001 and 2000,
respectively, were recorded as administrative and general expense. 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.
5. INVENTORIES
The major classes of inventories, which are included in other current assets, are as follows:
2002 2001
millions ---- ----
Materials and supplies $ 75 $ 61
Natural gas 16 18
Crude oil 15 22
---- ----
Total $106 $101
---- ----
|
6. PROPERTIES AND EQUIPMENT
A summary of the original cost of properties and equipment by classification follows:
2002 2001
millions ------- -------
Oil and gas properties $20,467 $18,047
Mineral properties 1,211 1,212
Gathering facilities 310 295
General properties 607 534
------- -------
Total $22,595 $20,088
------- -------
|
Oil and gas properties include costs of $3.1 billion and $3.6 billion at
December 31, 2002 and 2001, respectively, which were excluded from capitalized
costs being amortized. These amounts represent costs associated with unevaluated
properties and major development projects. At December 31, 2002 and 2001, the
Company's investment in countries where reserves have not been established was
$63 million and $53 million, respectively.
During 2002, 2001 and 2000, the Company made provisions for impairments of
U.S. and international properties of $39 million, $2.5 billion and $50 million,
respectively, which were related to oil and gas properties. In 2002, the Company
recorded international impairments of $39 million in Congo, Oman, Australia and
Tunisia primarily due to unsuccessful exploration activities. 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 $2.5 billion ($1.6 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
unsuccessful exploration activities in the United Kingdom and Ghana. In 2000,
the Company recorded international impairments of $50 million for unsuccessful
exploration activities in the United Kingdom, Tunisia and other international
locations.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
6. PROPERTIES AND EQUIPMENT (CONTINUED)
Total interest costs incurred during 2002, 2001 and 2000 were $358 million,
$301 million and $193 million, respectively. Of these amounts, the Company
capitalized $155 million, $209 million and $100 million during 2002, 2001 and
2000, 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 $196 million, $178 million and $124 million during 2002, 2001 and 2000,
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.
7. DEBT
A summary of debt follows:
2002 2001
-------------------------- --------------------------
PRINCIPAL CARRYING VALUE PRINCIPAL CARRYING VALUE
millions --------- -------------- --------- --------------
Notes Payable, Banks* $ 44 $ 44 $ 228 $ 228
Commercial Paper* 181 181 226 226
Long-term Portion of Capital Lease 7 7 9 9
6.8% Debentures due 2002 -- -- 88 88
6 3/4% Notes due 2003 73 73 73 73
5 7/8% Notes due 2003 83 83 83 83
6.5% Notes due 2005 170 166 170 164
7.375% Debentures due 2006 88 87 88 87
7% Notes due 2006 174 171 174 170
5 3/8% Notes due 2007 650 647 -- --
6.75% Notes due 2008 116 111 116 110
7.8% Debentures due 2008 11 11 11 11
7.3% Notes due 2009 85 83 85 82
6 3/4% Notes due 2011 950 912 950 910
6 1/8% Notes due 2012 400 395 -- --
5% Notes due 2012 300 297 -- --
7.05% Debentures due 2018 114 105 114 105
Zero Coupon Convertible Debentures due 2020 380 380 367 367
Zero Yield Puttable Contingent Debt Securities due
2021 30 30 650 650
7.5% Debentures due 2026 112 106 112 105
7% Debentures due 2027 54 54 54 54
6.625% Debentures due 2028 17 17 17 17
7.15% Debentures due 2028 235 212 235 212
7.20% Debentures due 2029 135 135 135 135
7.95% Debentures due 2029 117 117 117 117
7 1/2% Notes due 2031 900 862 900 862
7.73% Debentures due 2096 61 61 61 61
7 1/4% Debentures due 2096 49 49 49 49
7.5% Debentures due 2096 83 75 83 75
------ ------ ------ ------
Total debt $5,619 5,471 $5,195 5,050
------ ------
Less current portion 300 412
------ ------
Total long-term debt $5,171 $4,638
------ ------
|
* The average rates in effect at December 31, 2002 and 2001 were 1.57% and 2.55%, respectively, for Notes Payable, Banks. The average rates in effect at December 31, 2002 and 2001 were 1.88% and 2.59%, respectively, for Commercial Paper.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
7. DEBT (CONTINUED)
The Company recorded debt discount of $11 million, $40 million and $116
million in 2002, 2001 and 2000, respectively, as a result of debt issuances,
financial restructuring and corporate acquisitions. The unamortized debt
discount of $148 million and $145 million as of December 31, 2002 and 2001,
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.
The Company has commercial paper programs that allow Anadarko to borrow
funds, at rates as offered, by issuing notes to investors for terms of up to one
year.
At December 31, 2002, $761 million 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," $461 million of this amount is classified as long-term debt, since
Anadarko has the intent and ability to refinance this debt 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 Anadarko common stock at the option of the holder at any
time at a fixed conversion rate of 11.6288 shares of common stock per debenture.
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,
net of $6 million of debt offering expenses, were used initially to finance
costs associated with the acquisition of Berkley. In March 2002, ZYP-CODES in
the amount of $620 million were put to the Company for repayment and were paid
in cash. The ZYP-CODES are convertible into Anadarko common stock at the option
of the holder at any time at a fixed conversion rate of 9.9285 shares of common
stock per $1,000 principal amount of ZYP-CODES. Holders of the remaining
ZYP-CODES have the right to require Anadarko to purchase all or a portion of
their ZYP-CODES in March 2004, 2006, 2011 or 2016, at $1,000 per ZYP-CODES.
In April 2001, Anadarko Finance Company, a wholly-owned finance subsidiary
of Anadarko, issued $1.3 billion in notes to qualified institutional buyers
under Rule 144A and non-U.S. persons under Regulation S. 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
proceeds from the notes, net of $11 million in discounts, were used 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, net foreign currency translation gains of $19 million and losses of
$55 million for 2002 and 2001, respectively, were recorded as a component of
other comprehensive income.
In February 2002, the Company issued $650 million principal amount of
5 3/8% Notes due 2007. In March 2002, the Company issued $400 million principal
amount of 6 1/8% Notes due 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.
In April 2002, Anadarko filed a shelf registration statement with the SEC
that permits the issuance of up to $1 billion in debt securities, preferred
stock, preferred securities, depositary shares, common stock, warrants, purchase
contracts and purchase units. Net proceeds, terms and pricing of the offerings
of securities issued under the shelf registration statement will be determined
at the time of the offerings.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
7. DEBT (CONTINUED)
In September 2002, Anadarko issued $300 million principal amount of 5%
Notes due 2012. The net proceeds from the issuance were used to reduce floating
rate debt. These notes were issued under the shelf registration statement filed
in April 2002.
In October 2002, the Company entered into a 364-Day Revolving Credit
Agreement. The agreement provides for $225 million principal amount and expires
in 2003. Also in October 2002, Anadarko Canada Corporation (Anadarko Canada), a
wholly-owned subsidiary of Anadarko, entered into a 364-Day Canadian Credit
Agreement. The agreement provides for $300 million principal amount and expires
in 2003. 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. In
addition, the Company has a Revolving Credit Agreement that provides for $225
million principal amount and expires in 2004. As of December 31, 2002, the
Company had no outstanding borrowings under these bank credit agreements.
At December 31, 2002 and 2001, a Canadian subsidiary had $98 million and
$187 million, respectively, outstanding fixed-rate notes and debentures
denominated in U.S. dollars. During 2002, 2001 and 2000, the Company recognized
$5 million of gains, $25 million of losses and $8 million of losses,
respectively, before taxes associated with the remeasurement of this debt.
Total sinking fund and installment payments related to debt for the five
years ending December 31, 2007 are shown below. The payments related to a
portion of the Commercial Paper are included in the amounts shown in a manner
consistent with the terms for repayment of Anadarko's bank credit agreements.
millions 2003* $300 2004** 30 2005 170 2006 262 2007 650 |
* Holders of the Zero Coupon Convertible Debentures due 2020 had the right to put the debentures to the Company in March 2003 at the accrued value of $383 million. This debt instrument has not been reflected in the table above.
** Holders of the ZYP-CODES due 2021 may put the remaining $30 million principal amount of the ZYP-CODES to the Company in 2004.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. FINANCIAL INSTRUMENTS
The following information provides the carrying value and estimated fair value of the Company's financial instruments:
CARRYING
AMOUNT FAIR VALUE
millions -------- ----------
2002
Cash and cash equivalents $ 34 $ 34
Total debt 5,471 6,112
Commodity derivative instruments (including firm
transportation keep-whole agreement)
Asset 85 85
Liability (288) (288)
Foreign currency derivative instruments (8) (8)
2001
Cash and cash equivalents $ 37 $ 37
Total debt 5,050 5,170
Commodity derivative instruments (including firm
transportation keep-whole agreement)
Asset 105 105
Liability (217) (217)
Foreign currency derivative instruments (10) (10)
|
CASH AND CASH EQUIVALENTS The carrying amount reported on the balance sheet approximates fair value.
DEBT The fair value of debt at December 31, 2002 and 2001 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 and, where such quotes were not available, on the average rate in effect at year-end.
COMMODITY DERIVATIVE 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 derivative
instruments to manage fluctuations in cash flows resulting from changing
commodity prices. The Company also uses fixed price physical delivery sales
contracts to accomplish this objective. The types of instruments utilized by the
Company may include futures, swaps and options.
Anadarko also enters into commodity derivative 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 instruments are also used to meet customers' pricing
requirements while achieving a price structure consistent with the Company's
overall pricing strategy. In addition, the Company has used swap agreements to
reduce exposure to losses on its firm transportation keep-whole commitment with
Duke Energy Field Services, Inc. (Duke). Essentially all of the derivatives used
for trading purposes have a term of less than one year, with most having a term
of less than three months.
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 (NYMEX) 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
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. FINANCIAL INSTRUMENTS (CONTINUED)
the extent the counter-party is unable to meet its 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 a ceiling price (a collar) for the Company's expected future oil and gas sales. The Company buys and sells options through exchanges as well as in the over the counter market.
CASH FLOW HEDGES At December 31, 2002, the Company had option and swap contracts in place to fix floor and 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 oil production that extend through December 2003 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 oil production extend through December 2004 and associated with sales of gas production that extend through December 2004. As of December 31, 2002 and 2001, the Company had a net unrealized loss of $128 million before taxes, or $81 million after taxes, and a net unrealized gain of $7 million before taxes (gains of $9 million and losses of $2 million), or $4 million after taxes, respectively, on derivative instruments entered into to hedge production recorded in accumulated other comprehensive income. Other income for 2002 and 2001 included $33 million of net losses and $18 million of net gains, respectively, related to derivative instruments. These gains and losses were primarily due to recognition of unrealized gains and losses related to those hedges that did not qualify for hedge accounting and hedge ineffectiveness. Approximately $61 million after taxes of net losses in the accumulated other comprehensive income balance as of December 31, 2002 are expected to be reclassified into gas and oil sales during 2003 as the hedged transactions occur.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. FINANCIAL INSTRUMENTS (CONTINUED)
As of December 31, 2002 and 2001, the Company had the following volumes under derivative contracts related to its oil and gas producing activities (non-trading activity). The difference between the fair values in the table and the unrealized gain (loss) before income taxes recognized in accumulated other comprehensive income is due to premiums, recognition of unrealized gains and losses on certain derivatives that did not qualify for hedge accounting, hedge ineffectiveness and foreign currency hedges.
DECEMBER 31, 2002
NET FAIR VALUE
PRODUCTION ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE* VOLUMES AVERAGE PRICE MILLIONS
----------- ---------------- --------------- ----------------- -----------------
NATURAL GAS (million MMBtu) ($ per MMBtu)
2003 Swaps** 69 3.89 $ (46)
2003 3-way collars** 107 2.61-3.69-4.72 (29)
2004 Swaps** 70 3.88 (26)
2004 3-way collars** 58 2.48-3.47-4.91 (10)
2005 3-way collars** 3 2.20-3.00-5.05 --
2003 Swaps 4 3.88 (1)
2003 Calls sold 7 3.22 (3)
2003 Calls purchased 10 3.38 4
2003 2-way collars 2 3.00-5.00 (1)
2003 3-way collars 5 2.34-3.30-4.58 (2)
2004 Swaps 4 3.88 (1)
2004 Calls sold 1 2.98 --
2004 Calls purchased 1 2.98 --
2004 2-way collars 2 3.00-5.00 (1)
2004 3-way collars 3 2.20-3.00-4.60 (1)
2005 2-way collars 2 3.00-5.00 --
2005 3-way collars 3 2.20-3.00-4.60 (1)
-----
Total $(118)
-----
CRUDE OIL (MMBbls) ($ per barrel)
2003 Swaps** 5 25.31 $ (9)
2003 2-way collars** -- 22.30-23.32 (2)
2003 3-way collars** 16 18.91-24.31-27.62 (19)
2004 Swaps** 3 23.09 (1)
2003 3-way collars 3 17.00-21.00-26.13 (5)
2003 Calls sold 13 27.47 (23)
2003 Calls purchased 13 27.47 23
-----
Total $ (36)
-----
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. FINANCIAL INSTRUMENTS (CONTINUED)
DECEMBER 31, 2001
NET FAIR VALUE
PRODUCTION ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE* VOLUMES AVERAGE PRICE MILLIONS
----------- ---------------- --------------- ----------------- -----------------
NATURAL GAS (million MMBtu) ($ per MMBtu)
2002 2-way collars** 2 3.00-5.00 $ 1
2002 3-way collars** 7 2.20-3.00-4.83 2
2003 2-way collars** 2 3.00-5.00 1
2003 3-way collars** 7 2.20-3.00-4.83 1
2004 2-way collars** 2 3.00-5.00 1
2004 3-way collars** 7 2.20-3.00-4.83 1
2005 2-way collars** 2 3.00-5.00 1
2005 3-way collars** 7 2.20-3.00-4.83 1
2002 Calls sold 10 3.66 2
2002 Calls purchased 5 3.50 --
2003 Calls sold 7 3.18 (2)
2003 Calls purchased 10 4.12 2
2004 Calls sold 1 2.95 --
2004 Calls purchased 1 2.95 --
-----
Total $ 11
-----
CRUDE OIL (MMBbls) ($ per barrel)
2002 Swaps** 1 25.56 $ 2
2002 3-way collars** 3 19.11-23.33-30.51 6
-----
Total $ 8
-----
|
MMBtu -- million British thermal units
MMBbls -- million barrels
* A 2-way collar is a combination of options, a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (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 establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price the Company will receive for the volumes under contract.
** Qualifies for hedge accounting.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. 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 ACTIVITIES As of December 31, 2002 and 2001, the Company had the following volumes under derivative contracts related to its trading activity:
DECEMBER 31, 2002
NET FAIR VALUE
PRODUCTION ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE VOLUMES AVERAGE PRICE MILLIONS
----------- ----------------- --------------- ------------- -----------------
NATURAL GAS (million MMBtu) ($ per MMBtu)
2003 Futures sold 33 4.29 $ 18
2003 Futures purchased 28 4.15 (21)
2003 Swaps 80 4.25 26
2003 Calls sold 11 4.83 (1)
2003 Calls purchased 10 4.79 1
2003 Puts sold 3 3.77 --
2003 Puts purchased 4 3.66 --
2004 Futures sold 1 4.50 --
2004 Futures purchased 1 3.97 (1)
2004 Swaps 8 4.01 1
2005 Swaps 1 3.97 --
2006 Swaps 1 3.87 --
----
Total $ 23
----
|
CRUDE OIL (MMBbls) ($ per barrel)
2003 Futures sold 1 27.49 $ --
2003 Futures purchased 1 26.91 1
----
Total $ 1
----
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. FINANCIAL INSTRUMENTS (CONTINUED)
DECEMBER 31, 2001
NET FAIR VALUE
PRODUCTION ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE VOLUMES AVERAGE PRICE MILLIONS
---------- --------------- --------------- ------------- -----------------
NATURAL GAS (million MMBtu) ($ per MMBtu)
2002 Futures sold 24 3.34 $ 18
2002 Futures purchased 22 3.50 (21)
2002 Swaps 72 3.20 (42)
2002 Calls sold 8 3.07 1
2002 Calls purchased 13 4.09 1
2002 Puts sold 8 3.25 (7)
2002 Puts purchased 1 2.58 --
2003 Futures sold 1 3.51 --
2003 Futures purchased 1 3.36 --
2003 Swaps 12 3.12 --
----
Total $(50)
----
|
CRUDE OIL (MMBbls) ($ per barrel)
---------- --------------- -------------
2002 Futures sold 3 19.80 $ (1)
2002 Futures purchased 1 20.05 2
2002 Swaps 1 21.77 --
2002 Calls sold 1 29.50 --
----
Total $ 1
----
|
FIRM TRANSPORTATION KEEP-WHOLE AGREEMENT Anadarko Holding was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its 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, Anadarko Holding agreed to pay Duke if transportation market values fall below the fixed contract transportation rates, while Duke will pay Anadarko Holding if the transportation market values exceed the contract transportation rates (keep-whole agreement). 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 instruments to reduce its exposure under the Duke keep-whole agreement to potential decreases in future transportation market values. While 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. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward twelve months. Net receipts from Duke for 2002 and 2001 were $17 million and $161 million, respectively. This keep-whole agreement and any associated derivative instruments are accounted for on a mark-to-market basis. The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated with 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 expected drilling activity, anticipated pipeline construction projects, expected changes in demand at pipeline delivery points, etc.) that may impact the future market value of
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
8. FINANCIAL INSTRUMENTS (CONTINUED)
the firm transportation capacity to determine if the estimated fair value should
be adjusted. The Company recognized other income of $35 million, $91 million and
$175 million during 2002, 2001 and 2000, respectively, related to this agreement
and associated derivative instruments. As of December 31, 2002 accounts payable
included $5 million and other long-term liabilities included $68 million,
related to the keep-whole agreement. As of December 31, 2001, other current
assets included $25 million, accounts payable included $27 million and other
long-term liabilities included $80 million related to the keep-whole agreement
and associated derivative instruments.
Anticipated discounted and undiscounted liabilities for the firm
transportation keep-whole agreement at December 31, 2002 are as follows:
UNDISCOUNTED DISCOUNTED
millions ------------ ----------
2003 $ 5 $ 5
2004 28 24
2005 20 16
2006 19 13
2007 14 9
Later years 9 6
--- ---
Total $95 $73
--- ---
|
As of December 31, 2002, the Company had no natural gas volumes under derivative contracts related to the firm transportation keep-whole agreement. As of December 31, 2001, the Company had the following volumes of natural gas under derivative contracts related to the firm transportation keep-whole agreement:
NET FAIR VALUE
PRODUCTION VOLUMES AVERAGE PRICE ASSET (LIABILITY)
PERIOD INSTRUMENT TYPE (MILLION MMBTU) ($ PER MMBTU) MILLIONS
---------- --------------- --------------- ------------- -----------------
2002 Swaps 4* 8.42 $25
|
* Represents 2% of the Company's total volumetric exposure under the keep-whole agreement for 2002.
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.
At December 31, 2002 and 2001, the Company's Latin American subsidiaries
had foreign deferred tax liabilities denominated in the local currency
equivalent totaling $49 million and $78 million, respectively. During 2002, 2001
and 2000, the Company recognized tax benefits associated with remeasurement of
these deferred tax liabilities of $35 million, $6 million and $1 million,
respectively. In conjunction with the sale of certain properties in 2001, the
Company indemnified a purchaser for the use of local tax losses denominated in
local currency equivalent totaling $22 million. A loss of $1 million and a gain
of $1 million, before taxes, were recognized related to the remeasurement of
this liability and are included in other (income) expense during 2002 and 2001,
respectively.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
9. 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.
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. In the event of a
liquidation of the Company, the holders of the shares will be entitled to
receive liquidating distributions in the amount of $100 per Depositary Share
plus any accrued or unpaid dividends, before any distributions are made on the
Company's common stock.
Anadarko repurchased $2 million and $97 million of preferred stock during
2002 and 2001, respectively. No gain or loss was recorded in 2002 related to the
preferred stock repurchase activity. A gain of $13 million was recorded to
paid-in capital during 2001. During 2002, 2001 and 2000, dividends of $54.60 per
share (equivalent to $5.46 per Depositary Share) were paid to holders of
preferred stock.
10. COMMON STOCK AND STOCK OPTIONS
Following is a schedule of the changes in the Company's shares of common stock:
2002 2001 2000
millions ---- ---- ----
SHARES OF COMMON STOCK ISSUED
Beginning of year 254 253 130
Issuance of common stock -- -- 114
Exercise of stock options 1 1 6
Issuance of restricted stock -- -- 2
Issuance of shares for unearned employee stock ownership
plan -- -- 1
--- --- ---
End of year 255 254 253
--- --- ---
SHARES OF COMMON STOCK HELD IN TREASURY
Beginning of year 2 -- --
Purchase of treasury stock 1 2 --
--- --- ---
End of year 3 2 --
--- --- ---
SHARES OF COMMON STOCK HELD FOR UNEARNED EMPLOYEE STOCK
OWNERSHIP PLAN
Beginning of year 1 1 --
Issuance of stock -- -- 1
--- --- ---
End of year 1 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 249 249 250
--- --- ---
|
In the fourth quarter of 2002, dividends of 10 cents per share were paid to holders of common stock. For the first, second and third quarters of 2002 and 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, 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
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
10. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
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, 2002 and 2001.
In July 2000, the stockholders of Anadarko approved an increase in the
authorized number of Anadarko common shares from 300 million to 450 million. In
July 2000, each share of common stock of Anadarko Holding issued and outstanding
was converted into 0.455 shares of Anadarko common stock with approximately 114
million shares issued to the stockholders of Anadarko Holding.
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. The Company has 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 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 2002, the Company purchased 1
million shares of common stock for $50 million. During 2000, 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.
During 2002 and 2001 in conjunction with the stock purchase program,
Anadarko sold put options to independent third parties. These put options
entitled 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. A put option for 1 million shares was exercised
and put options for 2 million shares expired unexercised in 2001. Put options
for the remaining 2 million shares expired unexercised in 2002. During 2001,
premiums of $15 million were received related to these put options. In 2002, the
Company entered into a put option for 1 million shares of Anadarko common stock
with a notional amount of $46 million. The Company received premiums of $7
million during 2002. This put option expired unexercised in 2002. The premiums
for put options were recorded as increases to paid-in capital. The put options
permitted a net-share settlement at the Company's option and did not result in a
liability on the consolidated balance sheet.
As of December 31, 2002 and 2001, 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 $46 million and $33 million as of December 31, 2002 and 2001, 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 18.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
10. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
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.
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 2002, 2001 and 2000, the Company issued 0.2 million, 0.2 million
and 1.2 million shares, respectively, of restricted stock with a
weighted-average grant date fair value of $48.88, $61.26 and $50.21 per share,
respectively. In 2002, 2001 and 2000, expense related to restricted stock grants
was $15 million, $14 million and $8 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 Anadarko Holding merger transaction. In
2001 and 2000, administrative and general expense of $2 million and $25 million,
respectively, was recorded related to these shares. Also due to the Anadarko
Holding 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 4.
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.
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:
2002 2001 2000
------------------ ------------------ ------------------
WEIGHTED- Weighted- Weighted-
AVERAGE Average Average
EXERCISE Exercise Exercise
SHARES PRICE SHARES PRICE SHARES PRICE
option shares in millions ------ --------- ------ --------- ------ ---------
SHARES UNDER OPTION AT BEGINNING OF
YEAR 14.6 $42.49 14.4 $41.28 8.9 $29.94
Granted 1.4 $41.43 1.0 $58.12 7.4 $48.80
Anadarko Holding options assumed at
merger date -- $ -- -- $ -- 4.4 $38.93
Exercised (0.6) $32.53 (0.6) $32.93 (6.3) $32.32
Surrendered or expired (0.1) $53.35 (0.2) $59.72 -- $40.26
---- ---- ----
SHARES UNDER OPTION AT END OF YEAR 15.3 $42.68 14.6 $42.49 14.4 $41.28
---- ---- ----
Options exercisable at December 31 11.1 $40.93 7.9 $36.26 6.0 $33.91
---- ---- ----
Shares available for future grant at
end of year 2.5 3.6 4.8
---- ---- ----
Weighted-average fair value of
options granted during the year $18.86 $22.71 $19.09
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
10. COMMON STOCK AND STOCK OPTIONS (CONTINUED)
The following table summarizes information about the Company's stock options outstanding at December 31, 2002:
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
$ 0.00-$33.56 3.4 3.7 $27.34 3.3 $28.51
$33.60-$48.44 3.7 5.6 $40.23 2.3 $37.09
$48.53-$48.53 6.9 4.4 $48.53 4.8 $48.53
$48.94-$71.49 1.3 5.0 $58.60 0.7 $59.21
---- --- ------ ---- ------
Total 15.3 4.6 $42.68 11.1 $40.93
---- --- ------ ---- ------
|
The reconciliation between basic and diluted EPS is as follows:
FOR THE YEAR ENDED For the Year Ended For the Year Ended
DECEMBER 31, 2002 December 31, 2001 December 31, 2000
--------------------------- --------------------------- ---------------------------
PER SHARE Per Share Per Share
INCOME SHARES AMOUNT LOSS SHARES AMOUNT INCOME SHARES AMOUNT
millions except per share amounts ------ ------ --------- ------ ------ --------- ------ ------ ---------
BASIC EPS
Net income (loss) available to common
stockholders before change in
accounting principle $ 825 248 $ 3.32 $(183) 250 $(0.73) $ 813 184 $ 4.42
------ ------ ------
Effect of convertible debentures and
ZYP-CODES 9 10 -- -- 6 7
Effect of dilutive stock options,
performance-based stock awards and
common stock put options -- 2 -- -- -- 2
----- --- ----- --- ----- ---
DILUTED EPS
Net income (loss) available to common
stockholders plus assumed conversion $ 834 260 $ 3.21 $(183) 250 $(0.73) $ 819 193 $ 4.25
----- --- ------ ----- --- ------ ----- --- ------
|
For the years ended December 31, 2002, 2001 and 2000, options for 5.1 million, 1.2 million and 0.1 million average 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 respective period. For the years ended December 31, 2002 and 2001, put options for 0.5 million and 1.8 million average shares, respectively, 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.
11. STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION
The amounts of cash paid for interest (net of amounts capitalized) and income taxes are as follows:
2002 2001 2000
millions ---- ---- ----
Interest $175 $ 96 $90
Income taxes paid $ 67 $169 $40
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
11. STATEMENT OF CASH FLOWS SUPPLEMENTAL INFORMATION (CONTINUED)
The Anadarko Holding 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 4. 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 Anadarko Holding merger transaction of $147 million, less the cash acquired on the date of the Anadarko Holding merger transaction of $94 million.
12. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS
Anadarko has three Production Sharing Agreements (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 2002 was the registered owner of 4.9% of
Anadarko's outstanding common stock. Each PSA gives Anadarko the right to
explore, develop and produce liquid hydrocarbons in Algeria, subject to the
sharing of production with Sonatrach.
Anadarko has two partners in the Block 404/208 PSA. Approximately $23
million, $10 million and $10 million was paid to Sonatrach in 2002, 2001 and
2000, respectively, for charges related to transportation of oil, oil purchases,
well testing services, reservoir studies, laboratory services and equipment
usage. During 2002, 2001 and 2000, zero, $7 million and $6 million,
respectively, was received and $4 million and $7 million was included in
accounts payable as of December 31, 2002 and 2001, respectively, from Sonatrach
for joint interest billings of development costs in Algeria under the PSAs.
During 2000, Anadarko and Sonatrach formed a non-profit company, Groupement
Berkine, to carry out the majority of 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 Block 404/208
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 joint venture partners will spend a minimum of $55
million and began drilling exploration wells in 2002.
Anadarko signed two additional PSAs in 2001 and 2002 for Blocks 406b and
403c/e, respectively. The Company's interest in Block 406b is 100% and in Block
403c/e is 67%. Each agreement is for an initial three year exploration phase
with work commitments including 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 year ended December 31, 2000, approximately $4 million was
paid to Brown & Root-Condor under the EPC contracts.
Political unrest continues in Algeria. Anadarko continually monitors 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 unable to predict with certainty any effect the current
situation may have on activity planned for 2003 and beyond. However, the
situation has had no material effect to date on the Company's operations in
Algeria, where the Company has had activities since 1989. 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, Germany, Italy,
Mexico, Switzerland and Turkey. The majority of the Company's receivables are
paid within two months following the month of purchase.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
12. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS (CONTINUED)
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, 2002 and 2001, accounts
receivable are shown net of allowance for doubtful accounts of $16 million and
$44 million, respectively.
In 2002, 2001 and 2000, sales to Duke Energy and affiliates were $843
million, $1.4 billion and $1.0 billion, respectively, which accounted for 22%,
31% and 35% of the Company's total 2002, 2001 and 2000 revenues, respectively.
13. 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, marketing and trading activities and minerals activities. The oil
and gas exploration and production segment finds and produces natural gas, crude
oil, condensate and NGLs. The marketing and trading segment is responsible for
gathering, transporting and 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 Intercompany Eliminations and
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:
INTERCOMPANY
OIL AND GAS MARKETING ELIMINATIONS
EXPLORATION AND AND ALL
AND PRODUCTION TRADING MINERALS OTHER TOTAL
millions -------------- --------- -------- ------------- -------
2002
Revenues $ 2,443 $ 126 $ 41 $ 1,250 $ 3,860
Intersegment revenues 1,236 9 -- (1,245) --
------- ------ ------ ------- -------
Total revenues 3,679 135 41 5 3,860
Depreciation, depletion and
amortization 1,056 19 3 43 1,121
Impairments related to oil and
gas properties 39 -- -- -- 39
Other costs and expenses 907 116 2 250 1,275
------- ------ ------ ------- -------
Total costs and expenses 2,002 135 5 293 2,435
Other (income) expense -- (35) -- 253 218
------- ------ ------ ------- -------
Income (loss) before income
taxes $ 1,677 $ 35 $ 36 $ (541) $ 1,207
------- ------ ------ ------- -------
Net properties and equipment $13,204 $ 237 $1,202 $ 455 $15,098
------- ------ ------ ------- -------
Capital expenditures $ 2,310 $ 13 $ -- $ 65 $ 2,388
------- ------ ------ ------- -------
Goodwill $ 1,434 $ -- $ -- $ -- $ 1,434
------- ------ ------ ------- -------
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
13. SEGMENT AND GEOGRAPHIC INFORMATION (CONTINUED)
INTERCOMPANY
OIL AND GAS MARKETING ELIMINATIONS
EXPLORATION AND AND ALL
AND PRODUCTION TRADING MINERALS OTHER TOTAL
millions -------------- --------- -------- ------------- -------
2001
Revenues $ 3,172 $ 125 $ 57 $ 1,364 $ 4,718
Intersegment revenues 1,371 17 -- (1,388) --
------- ------ ------ ------- -------
Total revenues 4,543 142 57 (24) 4,718
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 950 115 4 312 1,381
------- ------ ------ ------- -------
Total costs and expenses 4,606 127 8 340 5,081
Other (income) expense -- (91) -- 118 27
------- ------ ------ ------- -------
Income (loss) before income
taxes $ (63) $ 106 $ 49 $ (482) $ (390)
------- ------ ------ ------- -------
Net properties and equipment $11,765 $ 253 $1,206 $ 413 $13,637
------- ------ ------ ------- -------
Capital expenditures $ 3,072 $ 66 $ -- $ 178 $ 3,316
------- ------ ------ ------- -------
Goodwill $ 1,430 $ -- $ -- $ -- $ 1,430
------- ------ ------ ------- -------
2000
Revenues $ 1,938 $ 48 $ 52 $ 873 $ 2,911
Intersegment revenues 866 66 -- (932) --
------- ------ ------ ------- -------
Total revenues 2,804 114 52 (59) 2,911
Depreciation, depletion and
amortization 570 8 2 13 593
Impairments related to oil and
gas properties 50 -- -- -- 50
Other costs and expenses 575 170 2 169 916
------- ------ ------ ------- -------
Total costs and expenses 1,195 178 4 182 1,559
Other (income) expense -- (174) -- 100 (74)
------- ------ ------ ------- -------
Income (loss) before income
taxes $ 1,609 $ 110 $ 48 $ (341) $ 1,426
------- ------ ------ ------- -------
Net properties and equipment $11,330 $ 166 $1,211 $ 304 $13,011
------- ------ ------ ------- -------
Capital expenditures $ 1,630 $ 41 $ -- $ 37 $ 1,708
------- ------ ------ ------- -------
Goodwill $ 1,317 $ -- $ -- $ -- $ 1,317
------- ------ ------ ------- -------
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
13. SEGMENT AND GEOGRAPHIC INFORMATION (CONTINUED)
The following table shows Anadarko's revenues (based on the origin of the sales) and net properties and equipment by geographic area:
2002 2001 2000
millions ------ ------ ------
REVENUES
United States $2,476 $3,537 $2,175
Canada 653 794 332
Algeria 572 195 271
Other International 159 192 133
------ ------ ------
Total $3,860 $4,718 $2,911
------ ------ ------
|
2002 2001
millions ------- -------
NET PROPERTIES AND EQUIPMENT
United States $11,258 $10,072
Canada 2,096 2,010
Algeria 898 807
Other International 846 748
------- -------
Total $15,098 $13,637
------- -------
|
14. OTHER TAXES
Significant taxes other than income taxes are as follows:
2002 2001 2000
millions ---- ---- ----
Production and severance $ 99 $139 $ 88
Ad valorem 91 85 28
Payroll and other 24 23 12
---- ---- ----
Total $214 $247 $128
---- ---- ----
|
15. OTHER (INCOME) EXPENSE
Other (income) expense consists of the following:
2002 2001 2000
millions ----- ----- -----
Firm transportation keep-whole contract valuation (See Note
8) $(35) $ (91) $(175)
Unrealized (gain) loss on derivative instruments 33 (18) --
Gas sales contracts -- accretion of discount 11 14 --
Foreign currency exchange* 1 29 7
Other 5 1 1
---- ----- -----
Total $ 15 $ (65) $(167)
---- ----- -----
|
* The years ended December 31, 2002, 2001 and 2000, exclude $35 million, $6 million and $1 million, respectively, in transaction gains related primarily to remeasurement of the Venezuelan deferred tax liability, which is included in income tax expense.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
16. INCOME TAXES
Income tax expense (benefit), including deferred amounts, is summarized as follows:
2002 2001 2000
millions ---- ----- ----
CURRENT
Federal $ (8) $ 32 $ 8
State 9 5 3
Foreign 178 50 67
---- ----- ----
Total 179 87 78
---- ----- ----
DEFERRED
Federal 194 (38) 405
State 10 (5) 24
Foreign (7) (258) 95
---- ----- ----
Total 197 (301) 524
---- ----- ----
Total $376 $(214) $602
---- ----- ----
|
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:
2002 2001 2000
millions ------ ----- ------
Income (Loss) Before Income Taxes
Domestic $ 706 $ 67 $1,085
Foreign 501 (457) 341
------ ----- ------
Total $1,207 $(390) $1,426
------ ----- ------
Statutory tax rate 35% 35% 35%
Tax computed at statutory rate $ 423 $(137) $ 499
Adjustments resulting from:
State income taxes (net of federal income tax benefit) 12 -- 17
Oil and gas credits (15) (22) (13)
Taxes related to foreign operations (net of federal income
tax benefit) (42) (51) 134
Reversal of goodwill amortization -- 22 11
Effect of change in Canadian income tax rates (5) (31) --
Other -- net 3 5 (46)
------ ----- ------
Total income tax expense (benefit) $ 376 $(214) $ 602
------ ----- ------
Effective tax rate 31% 55% 42%
------ ----- ------
|
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 2002, 2001 and 2000, the tax benefit amounted to $8
million, $6 million and $67 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 resulting in a net deferred
asset balance. A net tax liability of $24 million resulting from the Company's
restructuring of certain foreign operations in 2002 was recorded as an offset to
the account. The resulting deferred asset is reflected in the Company's other
long-term assets.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
16. INCOME TAXES (CONTINUED)
In 2001, tax expense in the amount of $10 million was recorded directly to
goodwill relating to the sale of a wholly-owned subsidiary, which was acquired
in a corporate acquisition.
The tax effects of temporary differences that give rise to significant
portions of the deferred tax liabilities (assets) at December 31, 2002 and 2001
are as follows:
2002 2001
millions ------ ------
Oil and gas exploration and development costs $2,938 $2,797
Mineral operations 419 422
Other 795 506
------ ------
Gross noncurrent deferred tax liabilities 4,152 3,725
------ ------
Net operating loss carryforward (28) --
Alternative minimum tax credit carryforward (146) (136)
Other (378) (169)
------ ------
Gross noncurrent deferred tax assets (552) (305)
Less: valuation allowance 33 31
------ ------
Net noncurrent deferred tax assets (519) (274)
Net noncurrent deferred tax liabilities $3,633 $3,451
------ ------
|
The $2 million net increase in the valuation allowance during 2002 is
primarily attributable to a change in judgment about the expected realization of
an existing foreign deferred tax asset.
Tax carryforwards at December 31, 2002, which are available for future
utilization on income tax returns, are as follows:
DOMESTIC FOREIGN EXPIRATION
millions -------- ------- ----------
Alternative minimum tax credit $146 $ -- Unlimited
General business tax credit $ 42 $ -- 2006-2021
Net operating loss $ -- $ 62 2003-2004
Capital loss - domestic $ 23 $ -- 2007
Capital loss - foreign $ -- $ 23 Unlimited
Foreign tax credit $ 4 $ -- 2005
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
17. COMMITMENTS
The Company has various commitments under non-cancelable operating lease agreements for buildings, facilities, aircraft 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, 2002, future minimum lease payments and receipts due under operating and capital leases are as follows:
OPERATING
CAPITAL OPERATING SUBLEASE
LEASES LEASES INCOME
millions ------- --------- ---------
2003 $ 3 $ 72 $(29)
2004 6 67 (6)
2005 1 55 (5)
2006 -- 52 (5)
2007 -- 53 (5)
Later years -- 208 (21)
--- ---- ----
Total future minimum lease payments 10 $507 $(71)
---- ----
Less: amounts representing interest (1)
---
Present value of minimum capital lease obligations 9
---
Less: short-term portion of capital lease obligations (2)
---
Long-term portion of capital lease obligations $ 7
---
|
Total rental expense, net of sublease income, amounted to $42 million, $43 million and $48 million in 2002, 2001 and 2000, respectively.
SYNTHETIC LEASES Anadarko has two lease arrangements for its corporate office
buildings in The Woodlands, Texas. The development and acquisition of the
properties were financed by special purpose entities (SPEs) sponsored by a
financial institution. The total amount funded under these leases was $213
million. The SPEs are not consolidated in the Company's financial statements,
and based on the terms of the agreements, the Company has accounted for these
arrangements as operating leases in accordance with SFAS No. 13, "Accounting for
Leases," and the table above includes the lease payment obligations.
The initial lease term for each lease is five years. Monthly lease payments
are based on the London interbank borrowing rate applied against the lease
balance. Future minimum lease payments are included in the above table. The
leases contain various covenants including covenants regarding the Company's
financial condition. Default under the leases, including violation of these
covenants, could require the Company to purchase the facilities for a specified
amount, which approximates the lessor's original cost ($213 million). As of
December 31, 2002, the Company was in compliance with these covenants.
At the end of the lease term, the Company has an option to either purchase
the facilities for the purchase option amount of the lease balance plus any
outstanding lease payments or to assist the SPEs in the sale of the properties.
The Company has provided a residual value guarantee for any deficiency if the
properties are sold for less than the sale option amount ($178 million at
December 31, 2002). In addition, the Company is entitled to any proceeds from a
sale of the properties 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. As such, no liability has been recognized for these guarantees
as of December 31, 2002.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
17. COMMITMENTS (CONTINUED)
In addition, the table above includes the Company's lease payment
obligations of $11 million related to aircraft operating leases financed by
synthetic leases. One of these aircraft leases is a synthetic lease with a
residual value guarantee for any deficiency if the aircraft is sold for less
than the sale option amount (approximately $11 million). In addition, the
Company is entitled to any proceeds from a sale of the aircraft in excess of the
sale option amount. No liability has been recorded related to this guarantee.
As discussed in Note l, the Company is evaluating the impact of the 2003
adoption of FIN No. 45 and FIN No. 46 on accounting for and the possible
restructuring of the synthetic leases and related guarantees.
PRODUCTION PLATFORM In April 2002, the Company signed an agreement 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 party to the agreement will construct and own the platform and production facilities that upon completion, expected in late 2003, will be operated by Anadarko. The agreement provides that Anadarko dedicate its production from Green Canyon Block 608 and 11 other Green Canyon blocks to the production facilities. The agreement requires 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 throughput. Since the Company's obligation to make these lease payments begins at the time of project completion, the table of future minimum lease payments above does not include any amounts related to this agreement. The agreement does not contain any purchase options, purchase obligations or value guarantees.
18. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS The Company has defined benefit pension plans and supplemental plans which are non-contributory pension plans. In January 2003, the Company made a $52 million contribution to one of the defined benefit pension plans. 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
18. 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, 2002 and 2001.
PENSION BENEFITS OTHER BENEFITS
---------------- ---------------
2002 2001 2002 2001
millions ----- ---- ----- -----
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ 417 $377 $ 123 $ 75
Service cost 14 11 5 3
Interest cost 29 27 8 5
Plan amendments -- 10 (7) 20
Actuarial loss 61 18 8 25
Foreign currency exchange rate change -- (2) -- --
Benefit payments and settlements (32) (24) (6) (5)
----- ---- ----- -----
Benefit obligation at end of year $ 489 $417 $ 131 $ 123
----- ---- ----- -----
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 338 $396 $ -- $ --
Actual return on plan assets (26) (32) -- --
Employer contributions 6 1 6 5
Foreign currency exchange rate change -- (3) -- --
Benefit payments (32) (24) (6) (5)
----- ---- ----- -----
Fair value of plan assets at end of year $ 286 $338 $ -- $ --
----- ---- ----- -----
Funded status of the plan $(203) $(79) $(131) $(123)
Unrecognized actuarial loss 195 80 31 23
Unrecognized prior service cost 8 8 8 16
Unrecognized initial asset (1) (2) -- --
----- ---- ----- -----
Total recognized $ (1) $ 7 $ (92) $ (84)
----- ---- ----- -----
TOTAL RECOGNIZED AMOUNTS IN THE BALANCE SHEET CONSIST
OF:
Prepaid benefit cost $ 24 $ 23 $ -- $ --
Accrued benefit liability (155) (51) (92) (84)
Intangible asset 11 31 -- --
Other comprehensive expense 119 4 -- --
----- ---- ----- -----
Total recognized $ (1) $ 7 $ (92) $ (84)
----- ---- ----- -----
|
Following are the weighted-average assumptions used by the Company in determining the accumulated pension and postretirement benefit obligations as of December 31, 2002 and 2001:
PENSION
BENEFITS OTHER BENEFITS
------------- ---------------
2002 2001 2002 2001
percent ---- ---- ----- -----
Discount rate 6.75% 7.25% 6.75% 7.25%
Long-term rate of return on plan assets 8.0% 9.0% N/A n/a
Rates of increase in compensation levels 5.0% 5.0% 5.0% 5.0%
|
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
18. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
(CONTINUED)
For measurement purposes, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2002. The rate was assumed to decrease gradually to 5% in 2006 and later years.
PENSION BENEFITS OTHER BENEFITS
------------------ ------------------
2002 2001 2000 2002 2001 2000
millions ---- ---- ---- ---- ---- ----
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 14 $ 11 $ 8 $ 5 $ 3 $ 2
Interest cost 29 27 15 8 6 4
Expected return on plan assets (31) (28) (13) -- -- --
Amortization values and deferrals 4 1 -- 1 (1) (1)
---- ---- ---- --- --- ---
Net periodic benefit cost $ 16 $ 11 $ 10 $14 $ 8 $ 5
---- ---- ---- --- --- ---
|
The projected benefit obligation, accumulated benefit obligation and fair
value of plan assets for the pension plans with accumulated benefit obligations
in excess of plan assets were $467 million, $404 million and $251 million,
respectively, as of December 31, 2002, and $395 million, $346 million and $297
million, respectively, as of December 31, 2001. The Company's benefit obligation
under the unfunded pension plans are secured by the Anadarko Petroleum
Corporation Executives and Directors Benefits Trust. See Note 10.
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:
1% INCREASE 1% DECREASE
millions ----------- -----------
Effect on total of service and interest cost components $ 2 $ (2)
Effect on postretirement benefit obligation $15 $(14)
|
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 $12 million, $11 million and $7 million during 2002, 2001 and 2000, respectively. The 2002 and 2001 contributions were funded through the Employee Stock Ownership Plan (ESOP).
EMPLOYEE STOCK OWNERSHIP PLAN In July 2000, Anadarko adopted the Anadarko
Holding ESOP and the shares in the ESOP were converted to shares of Anadarko
common stock. In July 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 Anadarko Holding Thrift Plan. All domestic regular
employees of Anadarko Holding were eligible to participate in the ESOP.
Effective December 31, 2000, the ESOP was merged into the Anadarko Holding
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 Anadarko Holding 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
18. PENSION PLANS, OTHER POSTRETIREMENT BENEFITS AND EMPLOYEE SAVINGS PLANS
(CONTINUED)
As of December 31, 2002 and 2001, the unallocated shares in the ESOP were 0.7 million and 0.9 million, respectively, and the fair value of unallocated ESOP shares at December 31, 2002 and 2001 was $32 million and $52 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 2002 and 2001, no compensation cost related to the allocation of ESOP shares, other than expense under the ESP, was recorded.
19. 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 Anadarko Holding 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 Civil False Claims Act,
the Company could be subject to a variety of sanctions, including treble damages
and substantial monetary fines. Motions to dismiss on the grounds that
plaintiffs did not provide new information for the government to file suit upon
were filed in January 2003, with a hearing date expected in May 2003.
A group of royalty owners purporting to represent Anadarko Holding'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 was asserted. The Company appealed the class certification order. A
favorable decision from the Houston Court of Appeals decertified the class. The
royalty owners did not appeal this matter to the Texas Supreme Court and the
decision from the Houston Court of Appeals became final in the second quarter of
2002. The royalty owners recently filed a new petition alleging that the class
may properly be brought so long as "sub-class" groups are broken out. The
Company is vigorously contesting this new petition.
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. It is uncertain at
this time when the trial court will render its ruling.
SUPERFUND -- OPERATING INDUSTRIES, INC. (FEDERAL) -- The former municipal industrial landfill, located in Monterey Park, California, was operational between 1948 and 1984. Anadarko Holding was noticed as a
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
19. CONTINGENCIES (CONTINUED)
Potentially Responsible Party in June 1986 for its Wilmington Production Field's and Wilmington Refinery's contributions. The Company participated in a settlement with the Environmental Protection Agency. The Company's share of the settlement was about $5 million.
CITGO LITIGATION CITGO Petroleum Corporation's (CITGO) claims arise out of an Asset Purchase and Contribution Agreement in 1987 whereby Anadarko Holding'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 Anadarko Holding 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, Anadarko Holding 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 Anadarko Holding. In conjunction with this matter, Anadarko Holding sued Continental Insurance for denial of coverage for claims related to this dispute. Anadarko Holding and Continental Insurance settled the insurance coverage litigation which resulted in Continental Insurance paying a portion of Anadarko Holding's claims. Negotiations and discussions with CITGO continue. Anadarko Holding has offered to settle all outstanding issues for approximately $4 million and a liability for this amount has been accrued.
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 charged 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 FERC and paid by Anadarko during 2001. The settlement agreement does
not have any impact on
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
19. CONTINGENCIES (CONTINUED)
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 quarter of 2003, that may result in payment of about $6 million by the Company. A provision was charged against income in 2001.
Other Litigation The Company has a reserve of about $2 million for Kansas ad valorem tax refunds. This amount reflects all principal and interest which may be due at the conclusion of all regulatory proceedings and litigation to parties other than PanEnergy.
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 Anadarko Holding 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. Thus, no liability has been recognized as of December 31, 2002.
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 amounts due under a revolving credit agreement and various letters of credit used to secure Industrial Revenue Bonds and environmental surety bonds. The Company's guarantee under the revolving credit agreement expires in 2005 coinciding with the maturity of that agreement. Expiration dates of the Company's guarantees under the letters of credit securing the Industrial Revenue Bonds and environmental surety bonds range from 2003 to 2004; however, it is the intent of the Company to renew these letters of credit and the related guarantees until the maturity dates of the obligations which range from 2003 to 2018. The amounts the Company would be obligated to pay should the affiliates default on these obligations would be up to $13 million for the revolving credit agreement, $8 million for environmental surety bonds and $15 million for the Industrial Revenue Bonds. No liability has been recognized for these guarantees as of December 31, 2002.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
19. CONTINGENCIES (CONTINUED)
In connection with its various acquisitions, the Company routinely
indemnifies the former officers and directors of acquired companies in respect
to acts or omissions occurring prior to the effective date of the acquisition.
The Company also agrees to maintain directors' and officers' liability insurance
on these individuals with respect to acts or omissions occurring prior to the
acquisition, generally for a period of six years. No liability has been
recognized for these indemnifications.
The Company also provides certain indemnifications in relation to
dispositions of assets. These indemnifications typically relate to disputes,
litigation or tax matters existing at the date of disposition. In connection
with a sale of properties in 2001, the Company indemnified 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 taxing
authorities. The Company believes it is probable that these losses will be
disallowed and will have to be settled with the purchaser in cash. The Company
has a $22 million liability recorded for the contingency.
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, 2002 and 2001 are $3.1 billion and $3.6 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
YEAR COSTS INCURRED EXCLUDED
---------------------------- COSTS AT
PRIOR DEC. 31,
YEARS 2000 2001 2002 2002
millions ----- ------ ---- ---- --------
Property acquisition $43 $1,085 $ 99 $193 $1,420
Exploration 25 646 423 284 1,378
Capitalized interest 5 50 109 123 287
--- ------ ---- ---- ------
Total $73 $1,781 $631 $600 $3,085
--- ------ ---- ---- ------
|
COSTS EXCLUDED BY COUNTRY
OTHER
U.S. CANADA ALGERIA INTERNATIONAL TOTAL
millions ------ ------ ------- ------------- ------
Property acquisition $1,355 $ 65 $ -- $ -- $1,420
Exploration 787 410 11 170 1,378
Capitalized interest 238 34 -- 15 287
------ ---- ----- ---- ------
Total $2,380 $509 $ 11 $185 $3,085
------ ---- ----- ---- ------
|
CHANGES IN COSTS EXCLUDED BY COUNTRY
OTHER
U.S. CANADA ALGERIA INTERNATIONAL TOTAL
millions ------- ------ ------- ------------- -------
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
Additional costs incurred in 2002 899 71 11 66 1,047
Costs transferred to DD&A pool in 2002 (1,279) (154) -- (102) (1,535)
------- ----- ---- ----- -------
DECEMBER 31, 2002 $ 2,380 $ 509 $ 11 $ 185 $ 3,085
------- ----- ---- ----- -------
|
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
2002 2001
millions ------- -------
UNITED STATES
Capitalized
Unproved properties $ 2,380 $ 2,760
Proved properties 12,639 10,464
------- -------
15,019 13,224
Accumulated depreciation, depletion and amortization 5,621 5,007
------- -------
Net capitalized costs 9,398 8,217
------- -------
CANADA
Capitalized
Unproved properties 509 592
Proved properties 2,870 2,493
------- -------
3,379 3,085
Accumulated depreciation, depletion and amortization 1,309 1,086
------- -------
Net capitalized costs 2,070 1,999
------- -------
ALGERIA
Capitalized
Unproved properties 11 --
Proved properties 1,052 907
------- -------
1,063 907
Accumulated depreciation, depletion and amortization 173 106
------- -------
Net capitalized costs 890 801
------- -------
OTHER INTERNATIONAL
Capitalized
Unproved properties 185 221
Proved properties 821 610
------- -------
1,006 831
Accumulated depreciation, depletion and amortization 160 83
------- -------
Net capitalized costs 846 748
------- -------
TOTAL
Capitalized
Unproved properties 3,085 3,573
Proved properties 17,382 14,474
------- -------
20,467 18,047
Accumulated depreciation, depletion and amortization 7,263 6,282
------- -------
Net capitalized costs $13,204 $11,765
------- -------
|
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
2002 2001 2000
millions ------ ------ ------
UNITED STATES -- Capitalized
Property acquisition
Exploration $ 341 $ 156 $1,897
Development 248 31 2,984
Exploration 654 840 353
Development 715 1,196 777
------ ------ ------
1,958 2,223 6,011
------ ------ ------
CANADA -- Capitalized
Property acquisition
Exploration 25 309 437
Development 3 835 1,075
Exploration 138 223 16
Development 237 233 89
------ ------ ------
403 1,600 1,617
------ ------ ------
ALGERIA -- Capitalized
Exploration 15 2 7
Development 140 179 155
------ ------ ------
155 181 162
------ ------ ------
OTHER INTERNATIONAL -- Capitalized
Property acquisition
Exploration 11 30 122
Development 26 67 532
Exploration 54 65 39
Development 108 136 33
------ ------ ------
199 298 726
------ ------ ------
TOTAL -- Capitalized
Property acquisition
Exploration 377 495 2,456
Development 277 933 4,591
Exploration 861 1,130 415
Development 1,200 1,744 1,054
------ ------ ------
$2,715 $4,302 $8,516
------ ------ ------
|
Development costs for 2002 include costs related to December 31, 2001 proved undeveloped reserves of $336 million for the United States, $65 million for Canada, $87 million for Algeria and $70 million for Other International, which total $558 million.
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 natural gas liquids (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.
2002 2001 2000
millions ------ ------ ------
UNITED STATES
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $1,581 $2,237 $1,443
Gas and oil sold to consolidated affiliates 804 1,212 660
------ ------ ------
2,385 3,449 2,103
Production (lifting) costs 605 671 418
Depreciation, depletion and amortization 710 792 429
Impairments related to oil and gas properties -- 1,701 --
------ ------ ------
1,070 285 1,256
Income tax expense 370 81 437
------ ------ ------
Results of operations $ 700 $ 204 $ 819
------ ------ ------
DD&A rate per net equivalent barrel $ 5.46 $ 5.54 $ 5.16
------ ------ ------
CANADA
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $ 633 $ 760 $ 298
Gas and oil sold to consolidated affiliates 12 23 20
------ ------ ------
645 783 318
Production (lifting) costs 224 203 85
Depreciation, depletion and amortization 215 225 76
Impairments related to oil and gas properties -- 808 --
------ ------ ------
206 (453) 157
Income tax expense (benefit) 87 (193) 70
------ ------ ------
Results of operations $ 119 $ (260) $ 87
------ ------ ------
DD&A rate per net equivalent barrel $ 6.09 $ 6.62 $ 6.12
------ ------ ------
ALGERIA
Net revenues from production
Third-party sales of oil $ 182 $ 59 $ 85
Oil sold to consolidated affiliates 392 136 186
------ ------ ------
574 195 271
Production (lifting) costs 41 21 23
Depreciation, depletion and amortization 69 24 26
------ ------ ------
464 150 222
Income tax expense 176 54 137
------ ------ ------
Results of operations $ 288 $ 96 $ 85
------ ------ ------
DD&A rate per net equivalent barrel $ 2.93 $ 3.00 $ 2.78
------ ------ ------
|
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (CONTINUED)
2002 2001 2000
millions ------ ------ ------
OTHER INTERNATIONAL
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $ 131 $ 193 $ 133
Oil sold to consolidated affiliates 28 -- --
------ ------ ------
159 193 133
Production (lifting) costs 68 80 61
Depreciation, depletion and amortization 62 69 39
Impairments related to oil and gas properties 39 37 50
------ ------ ------
(10) 7 (17)
Income tax expense (benefit) (4) 3 (9)
------ ------ ------
Results of operations $ (6) $ 4 $ (8)
------ ------ ------
DD&A rate per net equivalent barrel $ 7.75 $ 5.31 $ 5.36
------ ------ ------
TOTAL
Net revenues from production
Third-party sales of gas, oil, condensate and NGLs $2,527 $3,249 $1,959
Gas and oil sold to consolidated affiliates 1,236 1,371 866
------ ------ ------
3,763 4,620 2,825
Production (lifting) costs 938 975 587
Depreciation, depletion and amortization 1,056 1,110 570
Impairments related to oil and gas properties 39 2,546 50
------ ------ ------
1,730 (11) 1,618
Income tax expense (benefit) 629 (55) 635
------ ------ ------
Results of operations $1,101 $ 44 $ 983
------ ------ ------
DD&A rate per net equivalent barrel $ 5.36 $ 5.61 $ 5.08
------ ------ ------
|
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 Production Sharing
Agreement (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. Other international reserves are shown in accordance
with the respective PSA or risk service contract and are calculated using the
economic interest method.
The Company's reserves increased in 2002 primarily from exploration and
development drilling and corporate acquisitions, offset in part by production,
downward revisions to prior estimates and divestitures. The downward revisions
in 2002 were partially due to a downward price revision of 36 MMBOE in
Venezuela. Under the terms of Anadarko's risk service contract with the national
oil company of Venezuela, Anadarko earns a fee that is translated into barrels
of oil based on current prices. This means that higher oil prices reduce the
Company's reported oil reserves and production volumes from that project;
however, reserve and production fluctuations due to the economic interest
calculation have no impact on the value of the project. The Company's reserves
increased in 2001 primarily from exploration and development drilling and
corporate 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 a corporate acquisition, exploration and
development drilling, improved recovery and high gas prices at year-end 2000
compared to year-end 1999.
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.
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(UNAUDITED)
OIL AND GAS RESERVES (CONTINUED)
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, 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
REVISIONS OF PRIOR ESTIMATES 78 (42) (2) 34 33 (15) 5 (52) (29)
EXTENSIONS, DISCOVERIES AND OTHER
ADDITIONS 445 303 -- 748 51 8 3 -- 62
IMPROVED RECOVERY (6) -- -- (6) 8 -- -- -- 8
PURCHASES IN PLACE 86 1 -- 87 60 -- -- 13 73
SALES IN PLACE (53) (25) -- (78) (2) (24) -- -- (26)
PRODUCTION (505) (135) -- (640) (45) (13) (23) (8) (89)
----- ----- --- ----- --- --- --- --- -----
DECEMBER 31, 2002 5,693 1,343 144 7,180 578 64 372 117 1,131
----- ----- --- ----- --- --- --- --- -----
PROVED DEVELOPED RESERVES
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
DECEMBER 31, 2002 4,299 995 -- 5,294 377 46 191 72 686
|
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (CONTINUED)
(UNAUDITED)
OIL AND GAS RESERVES (CONTINUED)
TOTAL
(MMBOE)
----------------------------------------
OTHER
U.S. CANADA ALGERIA INT'L TOTAL
----- ------ ------- ----- -----
PROVED RESERVES
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
REVISIONS OF PRIOR ESTIMATES 46 (23) 5 (51) (23)
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 124 59 3 -- 186
IMPROVED RECOVERY 8 -- -- -- 8
PURCHASES IN PLACE 74 -- -- 13 87
SALES IN PLACE (11) (28) -- -- (39)
PRODUCTION (130) (35) (23) (8) (196)
----- --- --- --- -----
DECEMBER 31, 2002 1,526 288 372 142 2,328
----- --- --- --- -----
PROVED DEVELOPED RESERVES
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
DECEMBER 31, 2002 1,093 212 191 72 1,568
|
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, production, abandonment and
dismantlement 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, 2002, the present value (discounted at 10%) of future net
revenues from Anadarko's proved reserves was $21.1 billion, before income taxes,
and $14.1 billion, after income taxes, (stated in accordance with the
regulations of the SEC and the Financial Accounting Standards Board). The after
income taxes increase of $6.1 billion or 76% in 2002 compared to 2001 is
primarily due to significantly higher natural gas and crude oil prices at
year-end 2002, additions of proved reserves related to successful drilling
worldwide and corporate 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 $2.5
billion ($1.6 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.
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
2002 2001 2000
millions ------- ------- -------
UNITED STATES
Future cash inflows $36,536 $19,890 $57,027
Future production costs 8,989 6,072 8,175
Future development costs 2,142 1,759 1,182
------- ------- -------
Future net cash flows before income taxes 25,405 12,059 47,670
10% annual discount for estimated timing of cash flows 12,695 5,805 22,911
------- ------- -------
Discounted future net cash flows before income taxes 12,710 6,254 24,759
Future income taxes, net of 10% annual discount 4,113 1,764 8,546
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 8,597 4,490 16,213
------- ------- -------
CANADA
Future cash inflows 6,609 4,325 8,720
Future production costs 1,478 1,165 866
Future development costs 516 425 288
------- ------- -------
Future net cash flows before income taxes 4,615 2,735 7,566
10% annual discount for estimated timing of cash flows 2,048 1,030 3,261
------- ------- -------
Discounted future net cash flows before income taxes 2,567 1,705 4,305
Future income taxes, net of 10% annual discount 821 465 1,880
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 1,746 1,240 2,425
------- ------- -------
ALGERIA
Future cash inflows 11,597 7,466 8,410
Future production costs 1,209 1,113 1,011
Future development costs 478 313 408
------- ------- -------
Future net cash flows before income taxes 9,910 6,040 6,991
10% annual discount for estimated timing of cash flows 5,127 3,089 3,807
------- ------- -------
Discounted future net cash flows before income taxes 4,783 2,951 3,184
Future income taxes, net of 10% annual discount 1,747 1,109 1,108
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 3,036 $ 1,842 $ 2,076
------- ------- -------
|
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 (CONTINUED)
2002 2001 2000
millions ------- ------- -------
OTHER INTERNATIONAL
Future cash inflows $ 2,933 $ 2,242 $ 2,631
Future production costs 709 537 637
Future development costs 432 512 394
------- ------- -------
Future net cash flows before income taxes 1,792 1,193 1,600
10% annual discount for estimated timing of cash flows 747 562 705
------- ------- -------
Discounted future net cash flows before income taxes 1,045 631 895
Future income taxes, net of 10% annual discount 314 172 204
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves 731 459 691
------- ------- -------
TOTAL
Future cash inflows 57,675 33,923 76,788
Future production costs 12,385 8,887 10,689
Future development costs 3,568 3,009 2,272
------- ------- -------
Future net cash flows before income taxes 41,722 22,027 63,827
10% annual discount for estimated timing of cash flows 20,617 10,486 30,684
------- ------- -------
Discounted future net cash flows before income taxes 21,105 11,541 33,143
Future income taxes, net of 10% annual discount 6,995 3,510 11,738
------- ------- -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $14,110 $ 8,031 $21,405
------- ------- -------
|
Expected future development costs to develop proved undeveloped reserves as of December 31, 2002 in the United States are $970 million, $522 million and $190 million for 2003, 2004 and 2005, respectively. For Canada, the expected costs are $130 million, $76 million and $116 million for 2003, 2004 and 2005, respectively. For Algeria, the expected costs are $71 million, $64 million and $124 million for 2003, 2004 and 2005, respectively. For Other International, the expected costs are $54 million, $85 million and $41 million for 2003, 2004 and 2005, respectively. In total, the expected costs are $1.2 billion, $747 million and $471 million for 2003, 2004 and 2005, respectively.
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
2002 2001 2000
millions -------- -------- --------
UNITED STATES
Beginning of year $ 4,490 $ 16,213 $ 2,794
Sales and transfers of oil and gas produced, net of
production costs (1,780) (2,778) (1,685)
Net changes in prices and production costs 5,935 (19,309) 7,556
Changes in estimated future development costs (206) 183 (119)
Extensions, discoveries, additions and improved recovery,
less related costs 999 624 2,719
Development costs incurred during the period 331 337 126
Revisions of previous quantity estimates 441 (453) 114
Purchases of minerals in place 532 17 11,841
Sales of minerals in place (82) (5) (1)
Accretion of discount 625 2,476 386
Net change in income taxes (2,349) 6,782 (7,476)
Other (339) 403 (42)
-------- -------- --------
End of year 8,597 4,490 16,213
-------- -------- --------
CANADA
Beginning of year 1,240 2,425 --
Sales and transfers of oil and gas produced, net of
production costs (421) (580) (233)
Net changes in prices and production costs 774 (3,319) --
Changes in estimated future development costs (70) 2 --
Extensions, discoveries, additions and improved recovery,
less related costs 541 279 101
Development costs incurred during the period 157 101 --
Revisions of previous quantity estimates (259) (38) (165)
Purchases of minerals in place 3 593 4,568
Sales of minerals in place (96) (56) --
Accretion of discount 171 431 --
Net change in income taxes (356) 1,415 (1,880)
Other 62 (13) 34
-------- -------- --------
End of year 1,746 1,240 2,425
-------- -------- --------
ALGERIA
Beginning of year 1,842 2,076 1,588
Sales and transfers of oil produced, net of production costs (533) (174) (248)
Net changes in prices and production costs 2,316 (554) (330)
Changes in estimated future development costs (314) -- --
Extensions, discoveries, additions and improved recovery,
less related costs 85 56 901
Development costs incurred during the period 122 164 135
Accretion of discount 295 318 250
Net change in income taxes (638) (1) (197)
Other (139) (43) (23)
-------- -------- --------
End of year $ 3,036 $ 1,842 $ 2,076
-------- -------- --------
|
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)
2002 2001 2000
millions -------- -------- --------
OTHER INTERNATIONAL
Beginning of year $ 459 $ 691 $ --
Sales and transfers of oil and gas produced, net of
production costs (91) (113) (72)
Net changes in prices and production costs 757 (402) --
Changes in estimated future development costs 1 32 --
Extensions, discoveries, additions and improved recovery,
less related costs -- 109 --
Development costs incurred during the period 88 87 --
Revisions of previous quantity estimates (520) 75 --
Purchases of minerals in place 117 188 967
Sales of minerals in place -- (199) --
Accretion of discount 64 90 --
Net change in income taxes (142) 32 (204)
Other (2) (131) --
-------- -------- --------
End of year 731 459 691
-------- -------- --------
TOTAL
Beginning of year 8,031 21,405 4,382
Sales and transfers of oil and gas produced, net of
production costs (2,825) (3,645) (2,238)
Net changes in prices and production costs 9,782 (23,584) 7,226
Changes in estimated future development costs (589) 217 (119)
Extensions, discoveries, additions and improved recovery,
less related costs 1,625 1,068 3,721
Development costs incurred during the period 698 689 261
Revisions of previous quantity estimates (338) (416) (51)
Purchases of minerals in place 652 798 17,376
Sales of minerals in place (178) (260) (1)
Accretion of discount 1,155 3,315 636
Net change in income taxes (3,485) 8,228 (9,757)
Other (418) 216 (31)
-------- -------- --------
End of year $ 14,110 $ 8,031 $ 21,405
-------- -------- --------
|
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(UNAUDITED)
QUARTERLY FINANCIAL DATA
The following table shows summary quarterly financial data for 2002 and 2001. Certain amounts for prior periods have been reclassified to conform to the current presentation. See Note 1.
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
MILLIONS EXCEPT PER SHARE AMOUNTS ------- ------- ------- -------
2002
Revenues $ 790 $1,002 $ 951 $1,117
Operating income, pretax 204 364 363 494
Net income before cumulative effect of change in accounting
principle $ 89 $ 241 $ 190 $ 311
Net income available to common stockholders before
cumulative effect of change in accounting principle $ 88 $ 239 $ 189 $ 309
Net income available to common stockholders $ 88 $ 239 $ 189 $ 309
EPS - before cumulative effect of change in accounting
principle - basic $ 0.35 $ 0.96 $ 0.76 $ 1.25
EPS - before cumulative effect of change in accounting
principle - diluted $ 0.34 $ 0.93 $ 0.74 $ 1.21
EPS - basic $ 0.35 $ 0.96 $ 0.76 $ 1.25
EPS - diluted $ 0.34 $ 0.93 $ 0.74 $ 1.21
Average number common shares outstanding - basic 248 248 249 249
Average number common shares outstanding - diluted 263 259 258 258
2001
Revenues $1,588 $1,322 $1,010 $ 798
Operating income (loss), pretax(1) 979 620 (2,169)(2) 207
Net income (loss) before cumulative effect of change in
accounting principle(1) $ 664 $ 402 $(1,351)(2) $ 109
Net income (loss) available to common stockholders before
cumulative effect of change in accounting principle(1) $ 661 $ 401 $(1,353)(2) $ 108
Net income (loss) available to common stockholders(1) $ 656 $ 401 $(1,353)(2) $ 108
EPS - before cumulative effect of change in accounting
principle - basic $ 2.64 $ 1.60 $(5.41)(2) $ 0.43
EPS - before cumulative effect of change in accounting
principle - diluted $ 2.52 $ 1.50 $(5.41)(2) $ 0.41
EPS - basic $ 2.62 $ 1.60 $(5.41)(2) $ 0.43
EPS - diluted $ 2.50 $ 1.50 $(5.41)(2) $ 0.41
Average number common shares outstanding - basic 250 251 250 249
Average number common shares outstanding - diluted 263 268 250 266
|
(1) In January 2002, the Company discontinued the amortization of goodwill in accordance with Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." Goodwill amortization expensed in the first, second, third and fourth quarters of 2001 was $17 million, $19 million, $21 million and $16 million, respectively, both before and after taxes. See Note 3.
(2) Anadarko's operating loss for the third quarter 2001 includes a charge of $2.5 billion ($1.6 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.
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, Guidelines and Codes and Section 16(a) Beneficial Ownership Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement, dated March 24, 2003 (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 Board of Directors and Executive Compensation in the Proxy Statement, which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
See Stock Ownership in the Proxy Statement, which is incorporated herein by reference.
See Equity Compensation Plan Table appearing under Item 5 of this Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Board of Directors and Transactions with Management in the Proxy Statement, which is incorporated herein by reference.
ITEM 14. CONTROLS AND PROCEDURES
Anadarko's Chief Executive Officer and Chief Financial Officer (Certifying
Officers) performed an evaluation of the Company's disclosure controls and
procedures within 90 days of the filing of this Form 10-K. Disclosure controls
and procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by an issuer in the reports
that it files or submits under the Exchange Act is accumulated and communicated
to the issuer's management, including its Chief Executive Officer and Chief
Financial Officer, as appropriate to allow timely decisions regarding required
disclosure.
Based on this evaluation, the Certifying Officers have concluded that the
Company's disclosure controls and procedures are effective. In addition, there
have been no significant changes in the internal controls or in other factors
that could significantly affect these controls subsequent to the date of their
evaluation.
PART IV
ITEM 15. 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 53.
(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.
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 Anadarko Holding Company
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, ended September 30, 2000
as amended
(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, 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) 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
(ii) Anadarko Petroleum Corporation Amended 99 -- Attachment A to Form 1-8968
and Restated 1988 Stock Option Plan for 10-K for year ended December
Non-Employee Directors 31, 1993
(iii) 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
(iv) 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
(v) 1998 Director Stock Plan of Anadarko 99 -- Attachment A to Form 1-8968
Petroleum Corporation, effective January 10-K for year ended December
30, 1998 31, 1997
|
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
------- ----------------------------------------- ------------------------------- ---------
10(b) (vi) 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
(vii) 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
(viii) 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
(ix) 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
(x) 1993 Stock Incentive Plan 10(b)(xii) to Form 10-K for 1-8968
year ended December 31, 1993
(xi) First Amendment to Anadarko Petroleum 99 -- Attachment A to Form 1-8968
Corporation 1993 Stock Incentive Plans 10-K for year ended December
31, 1996
(xii) Second Amendment to Anadarko Petroleum 10(b)(xv) to Form 10-K for year 1-8968
Corporation 1993 Stock Incentive Plans ended December 31, 1997
(xiii) Anadarko Petroleum Corporation 1993 Stock 10(a) to Form 10-Q for quarter 1-8968
Incentive Plan Stock Option Agreement ended March 31, 1996
(xiv) 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
(xv) 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
(xvi) Anadarko Petroleum Corporation 1999 Stock 99 -- Attachment A to Form 1-8968
Incentive Plan 10-K for year ended December
31, 1998
(xvii) 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
(xviii) 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
(xix) 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
(xx) Annual Incentive Bonus Plan 10(b)(xiii) to Form 10-K for 1-8968
year ended December 31, 1993
|
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
------- ----------------------------------------- ------------------------------- ---------
10(b) (xxi) First Amendment to Anadarko Petroleum 99 -- Attachment B to Form 1-8968
Corporation Annual Incentive Bonus Plan 10-K for year ended December
31, 1998
*(xxii) Second Amendment to Anadarko Petroleum
Corporation Annual Incentive Bonus Plan
(xxiii) Key Employee Change of Control Contract 10(b)(xxii) to Form 10-K for 1-8968
year ended December 31, 1997
(xxiv) 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
(xxv) Anadarko Retirement Restoration Plan, 10(b)(xix) to Form 10-K for 1-8968
effective January 1, 1995 year ended December 31, 1995
(xxvi) Anadarko Savings Restoration Plan, 10(b)(xx) to Form 10-K for year 1-8968
effective January 1, 1995 ended December 31, 1995
(xxvii) Amendment to Amended and Restated 10(b)(xxxi) to Form 10-K for 1-8968
Anadarko Savings Restoration Plan year ended December 31, 1997
(xxviii) 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
(xxix) Anadarko Petroleum Corporation Estate 10(b)(xxxiv) to Form 10-K for 1-8968
Enhancement Program year ended December 31, 1998
(xxx) 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
(xxxi) Estate Enhancement Program Agreements 10(b)(xxxxii) to Form 10-K for 1-8968
effective November 29, 2000 year ended December 31, 2000
*(xxxii) Anadarko Petroleum Corporation Management
Life Insurance Plan
*(xxxiii) Management Disability Plan -- Plan
Summary
*12 Computation of Ratios of Earnings to
Fixed Charges and Earnings to Combined
Fixed Charges and Preferred Stock
Dividends
*13 Portions of the Anadarko Petroleum
Corporation 2002 Annual Report to
Stockholders
*21 List of Significant Subsidiaries
*23.1 Consent of KPMG LLP
*23.2 Consent of Ryder Scott Company
*24 Power of Attorney
|
EXHIBIT ORIGINALLY FILED FILE
NUMBER DESCRIPTION AS EXHIBIT NUMBER
------- ----------------------------------------- ------------------------------- ---------
*99.1 Anadarko Petroleum Corporation Proxy Filed on March 13, 2003
Statement, dated March 24, 2003
*99.2 Certification of Chief Executive Officer
and Chief Financial Officer
*99.3 Ryder Scott Company Report
|
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
A report on Form 8-K dated October 1, 2002 was filed in which the earliest
event reported was September 29, 2002. This event was reported under Item 5
"Other Events" and Item 7c. "Exhibits."
A report on Form 8-K dated November 1, 2002 was filed in which the earliest
event reported was October 31, 2002. This event was reported under Item 5 "Other
Events" and Item 7c. "Exhibits."
A report on Form 8-K dated December 6, 2002 was filed in which the earliest
event reported was December 6, 2002. This event was reported under Item 5 "Other
Events" and Item 7c. "Exhibits."
A report on Form 8-K dated December 13, 2002 was filed in which the
earliest event reported was December 13, 2002. This event was reported under
Item 5 "Other Events and Regulation FD Disclosure" and Item 7c. "Exhibits."
A report on Form 8-K dated December 20, 2002 was filed in which the
earliest event reported was December 20, 2002. This event was reported under
Item 5 "Other Events and Regulation FD Disclosure" and Item 7c. "Exhibits."
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 13, 2003 By: /s/ MICHAEL E. ROSE
-------------------------------------
(Michael E. Rose, Executive Vice
President 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 13, 2003.
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 and Chief Financial
------------------------------------------------ Officer
(Michael E. Rose)
(iii) Principal accounting officer:*
DIANE L. DICKEY Vice President and Controller
------------------------------------------------
(Diane L. Dickey)
(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
JOHN W. PODUSKA, SR., PH.D.
JOHN N. SEITZ
-----
* Signed on behalf of each of these persons and on his own behalf:
By /s/ MICHAEL E. ROSE
------------------------------------------------
(Michael E. Rose, Attorney-in-Fact)
|
CERTIFICATIONS
I, John N. Seitz, certify that:
1. I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
(a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 13, 2003
/s/ JOHN N. SEITZ
--------------------------------------
President and Chief Executive Officer
|
CERTIFICATIONS
I, Michael E. Rose, certify that:
1. I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
(a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 13, 2003
/s/ MICHAEL E. ROSE
--------------------------------------
Executive Vice President and Chief
Financial Officer
|
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
*10(b)(xxii) Second Amendment to Anadarko Petroleum Corporation Annual
Incentive Bonus Plan
*(xxxii) Anadarko Petroleum Corporation Management Life Insurance
Plan
*(xxxiii) Management Disability Plan -- Plan Summary
*12 Computation of Ratios of Earnings to Fixed Charges and
Earnings to Combined Fixed Charges and Preferred Stock
Dividends
*13 Portions of the Anadarko Petroleum Corporation 2002 Annual
Report to Stockholders
*21 List of Significant Subsidiaries
*23.1 Consent of KPMG LLP
*23.2 Consent of Ryder Scott Company
*24 Power of Attorney
*99.2 Certification of Chief Executive Officer and Chief Financial
Officer
*99.3 Ryder Scott Company Report
|
EXHIBIT 10(b)(xxii)
SECOND AMENDMENT TO
ANADARKO PETROLEUM CORPORATION
ANNUAL INCENTIVE BONUS PLAN
WHEREAS, ANADARKO PETROLEUM CORPORATION (the "Company") has heretofore adopted the ANNUAL INCENTIVE BONUS PLAN which was amended on January 1, 1995 (the "Plan"); and
WHEREAS, the Company desires to further amend the Plan in the manner and to the extent herein provided.
: NOW, THEREFORE, the Plan shall be amended, effective as of January 1, 1999, as follows:
1. The amount of "$1.5 million" in the fourth sentence of Section 4 shall be replaced with the amount of "$3 million".
2. Except as amended hereby, the Plan shall continue in full force and effect. .
IN WITNESS WHEREOF, the parties hereto have caused these presents to be executed this ____ day of January, 1999.
ANADARKO PETROLEUM CORPORATION
ATTEST:
_________________________ By:____________________________________
Charles G. Manley
Senior Vice President, Administration
|
EXHIBIT 10(b)(xxxii)
ANADARKO PETROLEUM CORPORATION
MANAGEMENT LIFE INSURANCE PLAN
(Restated November 1, 2002)
I.
ESTABLISHMENT OF THE PLAN
1.01 PURPOSE. Anadarko Petroleum Corporation (the "Company") hereby restates, effective November 1, 2002, the Anadarko Petroleum Corporation Management Life Insurance Plan (the "Plan") for the purpose of providing death benefits payable to the designated beneficiary or beneficiaries of selected employees and retirees of the Company in the event of the death of an employee or retiree. The Company intends that the Plan shall at all times be maintained on an unfunded basis for federal income tax purposes under the Internal Revenue Code of 1986, as amended (the "Code"), and administered as a "top hat" plan exempt from the substantive requirements of the Employee Retirement Income Security Act of 1974, as amended ("ERISA").
II.
DEFINITIONS
2.01 DEFINITIONS. Where the following words and phrases appear in the Plan, they shall have the respective meanings set forth below, unless their context clearly indicates to the contrary.
(1) ADMINISTRATOR: The Executive Vice President, Administration of the Company.
(2) BASE ANNUAL SALARY: The base annual compensation, excluding
bonuses, commissions, overtime, relocation expenses, incentive payments,
non-monetary awards, directors fees and other fees, paid to the Employee
for employment services rendered to the Company, before reduction for
compensation deferred pursuant to all qualified, non-qualified and Code
Section 125 plans of the Company.
(3) BENEFICIARY: The individual or entity designated by a Participant to receive the death benefit payable under the Plan upon the death of such Participant.
(4) BENEFIT SALARY: Benefit Salary is a Participant's base annual salary (if in $1,000 increments) or his base annual salary rounded up to the next $1,000.
(5) CHANGE OF CONTROL: A Change of Control will have the same meaning as such term is defined in either the Company's (i) Key Employee Change of Control Contract, or (ii) Change of Control Severance Pay Plan. The applicable definition of Change of Control will be based on the plan that the terminating Participant participates in, and if the Participant participates in both plans, the definition that is most favorable to the Participant.
(6) COMPANY: Anadarko Petroleum Corporation and any participating subsidiaries.
(7) DISABLED PARTICIPANT: A Participant who is receiving long term disability benefits under the Anadarko Petroleum Corporation Comprehensive Welfare Benefits Plan.
(8) EMPLOYEE: A person who is working for the Company and is classified as an employee of the Company.
(9) ERISA: The Employee Retirement Income Security Act of 1974, as amended.
(10) PARTICIPANT: Any Employee or Retiree of the Company who is designated a Participant of the Plan by the Administrator.
(11) PLAN: The Anadarko Petroleum Corporation Management Life Insurance Plan.
(12) PLAN YEAR: Each twelve consecutive month period ending on December 31.
(13) RETIREE: A former employee, who at the time of his separation of employment from the Company, is a Participant in the Plan and who is at least 55 years of age with at least 10 years of service and who is eligible to participate in the Company's retiree medical and dental plans.
2.02 NUMBER AND GENDER. Wherever appropriate herein, words used in the singular shall be considered to include the plural and the plural to include the singular. The masculine gender, where appearing in this Plan, shall be deemed to include the feminine gender.
III.
BENEFITS
3.01 BENEFITS. Benefits under the Plan shall be contingent on the continued employment, disability, or retirement of the Participant. In the event the employment of the Participant by the Company is terminated for any reason other than retirement, disability, or due to a Change of Control, then the Plan shall have no further obligation to the Participant.
3.02 DISABILITY BENEFITS. A Disabled Participant will be treated as if he or she is actively employed by the Company for purposes of determining the amount of benefits to which the Disabled Participant is entitled under the Plan. If a Disabled Participant is no longer receiving long term disability benefits from the Company, then his or her status under the Plan will be determined based on the nature of the Participant's employment status with the Company immediately thereafter.
3.03 CHANGE OF CONTROL BENEFITS. In the event the employment of the Participant by the Company is terminated due to a Change of Control and the Participant receives a benefit under a Change of Control plan of the Company, then the Participant will be treated as if he or she is a Retiree for purposes of determining the amount of benefits to which the Participant is entitled under the Plan.
3.04 AMOUNT OF BENEFITS. In the event of the death of a Participant while employed by the Company, the Company shall thereafter pay a lump sum cash payment (the "Benefit Payment") equal to four (4) times the Participant's Benefit Salary less two (2) times Benefit Salary or the maximum benefit under the Company's Basic Life Insurance Plan in effect at the time of death, whichever is less. The payment will be made as soon as administratively feasible following the date of his or her death, to the Participant's designated Beneficiary, in accordance with the last such designation received by the Company from the Participant prior to his or her death. In the event of the death of a Participant who is a Retiree, the Company shall thereafter pay a lump sum cash payment (the "Benefit Payment") equal to one (1) times the Retiree's Benefit Salary in effect at the time of his or her retirement as soon as administratively feasible following the date of his or her death, to the Retiree's designated Beneficiary, in accordance with the last such designation received by the Company from the Retiree prior to his or her death.
In addition, the Company shall pay to the Beneficiary an additional amount (the "Gross-Up Payment") such that the net amount retained by the Beneficiary from both the Gross-Up Payment and the Benefit Payment combined, after deduction of any federal income, federal employment, and state and local income tax withholding from the Benefit Payment and the Gross-Up Payment, shall be equal to the Benefit Payment amount.
For purposes of determining the amount of the Gross-Up Payment, the rate of federal income tax withholding shall be deemed to be the highest marginal rate of federal income taxation in effect in the calendar year in which the Benefit Payment and Gross-Up Payment are made. The rate of federal employment tax withholding shall be deemed to be the highest rate of Medicare taxation in effect in the calendar year in which the Benefit Payment and Gross-Up Payment are made. The rate of state and local income tax withholding, if applicable, shall be deemed to be the highest marginal rate of state and local income taxation, in the state and locality of the Participant's residence on the date of death, in effect in the calendar year in which the Benefit Payment and Gross-Up Payment are made.
3.05 TIME FOR PAYMENT. The benefits which are payable hereunder with respect to a Participant shall be paid as soon as administratively feasible after (i) the Administrator has obtained all information, including a properly notarized certificate of death, from the Participant's Beneficiary necessary to establish that a death benefit with respect to such Participant is payable to such Beneficiary under the Plan, and (ii) the Administrator has directed the payment of such death benefit.
At the discretion of the Company, a Retiree will receive the actuarial present value of the Benefit Payment and Gross-up Payment at retirement based on the interest rate and mortality assumptions used for determining lump sum payments under the Anadarko Retirement Plan in effect at the time of retirement.
3.06 BENEFICIARIES. Each Participant shall have the right to designate the Beneficiary or Beneficiaries to receive payment of any death benefit payable under the Plan in the event of his death. A Participant's Beneficiary designation in effect for the Company's Basic Life Insurance Plan will determine the Beneficiary or Beneficiaries under this Plan, unless otherwise designated by the Participant. Each such designation shall be made by executing the appropriate form prescribed by the Administrator and filing same with the Administrator. Any such designation may be changed at any time by execution of a new Beneficiary designation by the Participant. If no Beneficiary designation is on file with the Administrator at the time of the death of a Participant or such Beneficiary designation is not effective for any reason as determined by the Administrator, the Beneficiary or Beneficiaries to receive the death benefit payable with respect to such Participant under the Plan shall be as follows in the order named:
(1) If a Participant leaves a surviving spouse, the death benefit payable under the Plan with respect to such Participant shall be paid to such surviving spouse;
(2) If a Participant leaves no surviving spouse, the death benefit payable with respect to such Participant under the Plan shall be paid to such Participant's executor or administrator or to his heirs-at-law if there is no administrator of such Participant's estate.
3.07 DIVORCE OF PARTICIPANT. In the event a Participant receives a final divorce decree order, and if the Participant's current Beneficiary designation reflects the former spouse as a Beneficiary or contingent Beneficiary, then the Plan will deem any such designation of the former spouse null and void as of the date of the final divorce decree unless such decree specifies that the former spouse is required to remain as a Beneficiary. A former spouse may be designated as a Beneficiary, provided the designation is executed after the date of the final divorce decree and there is nothing to the contrary provided in the final divorce decree.
IV.
ADMINISTRATION OF THE PLAN
4.01 ADMINISTRATOR. The Plan shall be administered on behalf of the Company by the Administrator. For purposes of ERISA, the Administrator shall be the Plan "administrator" and shall be the "named fiduciary" with respect to the general administration of the Plan.
4.02 ADMINISTRATOR'S POWERS AND DUTIES. The Administrator shall have all powers necessary or proper to administer the Plan and to discharge its duties under the Plan, including, but not limited to, the following powers:
(a) To make and enforce such rules and regulations as it may deem necessary or proper for the orderly and efficient administration of the Plan;
(b) To interpret the Plan, its interpretation thereof in good faith to be final and conclusive on all persons claiming benefits under the Plan;
(c) To determine who is eligible to participate in the Plan;
(d) To determine Participants' rights and the amounts of Plan benefits and to authorize the payment of benefits under the Plan;
(e) To prepare and distribute information explaining the Plan;
(f) To appoint or employ persons to assist in the administration of the Plan; and
(g) To obtain such information as is necessary for the proper administration of the Plan.
4.03 EXPENSES. The expenses incident to the operation of the Plan shall be paid by the Company.
4.04 BENEFIT CLAIMS PROCEDURES. If a Plan benefit claim is denied in whole or in part with respect to a Participant, the Participant or his Beneficiary shall receive not later than 90 days after receipt of the claim, a written notice which:
(a) states the specific reason or reasons for the denial;
(b) provides specific references to pertinent Plan provisions on which the denial is based;
(c) provides a description of any additional material or information necessary for the Participant, his Beneficiary or representative to perfect the claim and an explanation of why such material or information is necessary; and
(d) explains the Plan's claim review procedure as contained herein and the time limits applicable to such procedures, including a statement of the right to bring a civil action under Section 502(a) of ERISA following an adverse decision upon review.
In the event the Participant or his Beneficiary desires to have such denial reviewed, he must, within sixty days following receipt of the notice of such denial, submit a written request for review by the Administrator of its initial decision. In connection with the request for review of the denial, the Participant or his Beneficiary shall have the following rights:
(a) the opportunity to submit written documents, comments, records or other relevant information;
(b) the right to have all materials relating to the claim that have been submitted by the Participant or his Beneficiary in connection with the original claim considered on review without regard to whether they were considered in the initial benefit determination; and
(c) the right of reasonable access to and copies of all relevant documents, records or other information free of charge upon request.
Within sixty days following such request for review the Administrator shall render its final decision in writing to the Participant or his Beneficiary and the notice of such final decision if it is adverse upon review will:
(a) state the specific reason or reasons for the adverse decision;
(b) provide specific reference to pertinent Plan provisions on which the adverse decision was based;
(c) state that the Participant or his Beneficiary is entitled to receive upon request and free of charge copies of all documents, records and other information relevant to his claim for benefits and the denial on review; and
(d) describe the Participant's or his Beneficiary's right to bring an action under Section 502(a) of ERISA.
If special circumstances require an extension of such sixty-day period, the Administrator's decision shall be rendered as soon as possible, but not later than 120 days after receipt of the request for review. If an extension of time for review is required, written notice of the extension shall be furnished to the Participant or his Beneficiary prior to the commencement of the extension period.
4.05 LIABILITY OF ADMINISTRATOR. The Company agrees to indemnify the Administrator and any agent of the Administrator against all liabilities, damages, costs and expenses (including attorneys' fees and amounts paid in settlement of any claims approved by the Company) occasioned by any act or omission to act in connection with the Plan if such act or omission was in good faith.
4.06 INSTRUCTIONS OF ADMINISTRATOR. Any instructions of the Administrator shall be evidenced in writing and signed by the Administrator or by an agent of the Administrator, who has been authorized by the Administrator to give such instructions.
V.
AMENDMENTS AND TERMINATION
5.01 AMENDMENTS. The Company reserves the right to, from time to time, amend this Plan. The Company may make any amendment it determines to be necessary or desirable, with or without retroactive effect.
5.02 RIGHT TO TERMINATE. The Company hopes and expects to continue this Plan for the Participants indefinitely. The Company reserves the right at will and without prior notice to terminate or partially terminate the Plan or any portion thereof. No such termination shall adversely affect the rights of Beneficiaries of deceased Participants with respect to benefits which became payable as a result of the deaths prior to the date of such termination of the Plan. If the Plan is terminated or partially terminated by the Company, each Retiree who is then still living and who has not previously received a Retiree death benefit under this Plan, will be entitled to the actuarial present value of his or her death benefit under the Plan, calculated under the same terms and conditions that a lump sum is determined under the Anadarko Retirement Plan.
VI.
GENERAL PROVISIONS
6.01 RIGHT TO BENEFITS. No Participant, or Beneficiary through such Participant, shall have any right to, or interest in, any benefits provided under this Plan, except as provided under this Plan.
6.02 NONALIENATION OF BENEFITS. No interest in or benefit payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance or charge.
6.03 UNFUNDED STATUS. The Plan shall constitute an unfunded, unsecured obligation of the Company to make death benefit payments in accordance with the provisions of the Plan. Neither the establishment of the Plan nor the maintenance on the books of the Company of accounts for Participants shall be deemed to create a trust and no Participant or Beneficiary of such Participant shall have any claim against the Company except with respect to the payment of death benefit payments in accordance with the provisions of the Plan. In the event the Company purchases an insurance policy or policies, insuring the life of a Participant to allow the Company to recover, in whole, or in part, the cost of providing the Benefit Payment, neither the Participant nor any of his or her Beneficiaries shall have or acquire any right whatsoever therein or in the proceeds therefrom. The Company shall be the sole owner of any such policy or policies, and, as such, shall possess and may exercise all incidents of ownership. No such policy, policies or other property shall be held in any trust for the Participant or any other person as collateral security for any obligation of the Company hereunder. In order for a person to become a Participant or continue to be a Participant in the Plan, the Company reserves the right to require such person or Participant to carry out whatever functions are required of such person or Participant in order for the Company to secure an insurance policy or policies or other property to be used to offset the cost of providing the benefits under the Plan.
6.04 CONSTRUCTION. Except to the extent that ERISA applies to this Plan, the Plan shall be construed, enforced and administered according to the laws of the State of Texas. The Company intends that the terms of the Plan, including those relating to coverage and benefits, are legally enforceable. In case any provision of the Plan is held to be illegal or invalid for any reason, it shall not affect the remaining provisions of the Plan, but the Plan shall be construed and enforced as if such illegal or invalid provision had not been included therein.
6.05 EXCLUSIVE BENEFIT. The Plan is to be maintained for the exclusive benefit of the Participants.
IN WITNESS WHEREOF, the Company has caused this Plan to be adopted and to be signed by its duly authorized officers.
EXHIBIT 10(b)(xxxiii)
MANAGEMENT DISABILITY PLAN
PLAN SUMMARY
INTRODUCTION As a member of Anadarko's key management team, you are
eligible to participate in the Management Disability Plan
(the "Plan"). The Plan is designed to replace up to 70% of
your base salary in the event you are unable to work due to
a serious injury or illness. Your coverage in this Plan
replaces your coverage in the Anadarko Petroleum Corporation
Disability Plan (the "Group LTD Plan") which provided a
benefit of up to 60% of your base salary. There is no cost
to you for coverage under the Plan and there are no
enrollment forms to complete.
DEFINITION The Plan defines disability as a condition which prevents
OF DISABILITY you from performing all of the material duties of your
occupation. The insurance carrier will make the final
determination as to whether you qualify for disability
benefits.
After receiving benefits for 24 months, your disability will
be reviewed. You will continue to receive benefits if you
are still unable to perform all of the material duties of
your occupation on a full-time basis and are earning at
least 20% less than before you became disabled.
DISABILITY Your maximum monthly benefit under the Plan is 70% of your
BENEFIT base monthly earnings in effect immediately prior to the
date your disability began. The maximum monthly benefit
payable under the Plan cannot exceed $35,000.
If you are partially disabled but able to work in your
regular occupation or another occupation, your benefit
calculation will consider other earnings you may be
receiving. During the first twelve months, your benefit will
be calculated by subtracting other earnings from your
pre-disability salary. After twelve months, other earnings
may result in a further reduction of your benefits.
1
|
Your benefit is also subject to reduction by any disability
payments from Social Security, Workers' Compensation and
government disability or retirement plans.
WAITING Benefits will begin after you have been disabled for 180
PERIOD days. When you submit your claim for disability benefits,
you must provide proof that you are disabled and that you
are under the care of a physician.
PRE-EXISTING A pre-existing condition is a sickness or injury for which
CONDITION you have received medical treatment, consultation or
EXCLUSION prescription medication in the six months prior to the
effective date of your coverage under the Plan.
If you have a qualifying pre-existing condition, your
benefits under the Plan may be reduced up to 10%.
Once you are able to go treatment free for 12 months, you
will be eligible for full benefits under the Plan. After you
have been covered under the Plan for 24 months, your
pre-existing condition will no longer be considered and you
will be eligible for full benefits under the Plan.
TAXATION Benefit payments are fully taxable as ordinary income.
OF BENEFITS
MAXIMUM If you become disabled prior to age 60, benefits will
BENEFIT continue until age 65 as long as you continue to meet the
PERIOD definition of disability. If you become disabled after
age 60, the maximum benefit period is shown on the following
page.
|
---------------------------------------------------
AGE AT DISABILITY MAXIMUM BENEFIT PERIOD
---------------------------------------------------
60 60 Months
---------------------------------------------------
61 48 Months
---------------------------------------------------
62 42 Months
---------------------------------------------------
63 36 Months
---------------------------------------------------
64 30 Months
---------------------------------------------------
65 24 Months
---------------------------------------------------
66 21 Months
---------------------------------------------------
67 18 Months
---------------------------------------------------
68 15 Months
---------------------------------------------------
69 and over 12 Months
---------------------------------------------------
|
Benefits for disability due to mental illness will not
exceed a 24 month period regardless of age.
CESSATION Your benefit payments will stop at the earliest of the
OF BENEFITS following events:
- You are no longer disabled,
- The maximum benefit period has expired,
- Your death,
- Your current earnings exceed 80% of your pre-disability
earnings.
COVERAGE Your coverage under the Plan will end upon your retirement
END DATE or termination of employment with the Company, or if you are
no longer determined to be an eligible participant or the
Plan is discontinued.
3
|
CONVERSION You may convert your coverage under the Plan to an
individual policy if your employment is terminated or you
become ineligible to participate in the Plan.
OTHER This information is a brief overview of the Plan. Additional
INFORMATION information regarding the Plan is provided in the plan
document. If there is a conflict between the information
provided in the summary and the plan document, the plan
document will prevail.
The Company retains the right to terminate or amend the Plan
at any time.
|
EXHIBIT 12
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF COMPUTATION OF RATIOS OF
EARNINGS TO FIXED CHARGES AND EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
FIVE YEARS ENDED DECEMBER 31, 2002
Years Ended December 31
-------------------------------------------
millions except ratio amounts 2002 2001 2000 1999 1998
------ ----- ------ ---- -----
Gross Income (Loss) $1,410 $(298) $1,519 $179 $ (7)
Rentals 14 14 16 11 12
------ ----- ------ ---- -----
Earnings (Loss) 1,424 (284) 1,535 190 5
------ ----- ------ ---- -----
Gross Interest Expense 358 301 193 96 82
Rentals 14 14 16 11 13
------ ----- ------ ---- -----
Fixed Charges $ 372 $ 315 $ 209 $107 $ 95
------ ----- ------ ---- -----
Preferred Stock
Dividends 9 11 17 17 11
------ ----- ------ ---- -----
Combined Fixed Charges
and Preferred Stock
Dividends $ 381 $ 326 $ 226 $124 $ 106
------ ----- ------ ---- -----
Ratio of Earnings to
Fixed Charges 3.83 n/m 7.35 1.77 0.05
------ ----- ------ ---- -----
Ratio of Earnings to
Combined Fixed Charges
and Preferred Stock
Dividends 3.74 n/m 6.80 1.53 0.05
------ ----- ------ ---- -----
|
n/m - not meaningful
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. In 1998, Anadarko's earnings did not cover fixed charges by $90 million and did not cover combined fixed charges and preferred stock dividends by $101 million.
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.
.
.
.
EXHIBIT 13
FIVE YEAR FINANCIAL HIGHLIGHTS*
---------------------------------------------------------------------------------------------------------
DOLLARS IN MILLIONS, % change
EXCEPT PER SHARE AMOUNTS 2002 2002-2001 2001 2000 1999 1998
------------------------ ------- --------- ------- ------- ------ -------
Revenues $ 3,860 (18) $ 4,718 $ 2,911 $ 748 $ 607
Operating Income (Loss) 1,425 n/m (363) 1,352 175 (8)
Net Income (Loss) Available to
Common Stockholders before
Change in Accounting Principle 825 n/m (183) 813 32 (49)
Net Income (Loss) 825 n/m (188) 796 32 (49)
Net Cash Provided by Operating Activities $ 2,196 (34) $ 3,321 $ 1,536 $ 318 $ 240
Per Common Share:
Net Income (Loss) -- Basic $ 3.32 n/m $ (0.75) $ 4.32 $ 0.25 $ (0.41)
Net Income (Loss) -- Diluted $ 3.21 n/m $ (0.75) $ 4.16 $ 0.25 $ (0.41)
Dividends $ 0.325 44 $ 0.225 $ 0.20 $ 0.20 $0.1875
Average Shares Outstanding -- Basic 248 (1) 250 184 125 120
Average Shares Outstanding -- Diluted 260 4 250 193 126 120
Capital Expenditures $ 2,388 (28) $ 3,316 $ 1,708 $ 680 $ 917
---------------------------------------------------------------------------------------------------------
Total Debt $ 5,471 8 $ 5,050 $ 3,984 $1,443 $ 1,425
Stockholders' Equity 6,972 10 6,365 6,786 1,535 1,259
Total Assets $18,248 9 $16,771 $16,590 $4,098 $ 3,633
---------------------------------------------------------------------------------------------------------
Annual Sales Volumes:
Gas (Bcf) 642 (8) 695 385 170 177
Oil and Condensate (MMBbls) 75 10 68 36 15 11
NGLs (MMBbls) 15 -- 15 12 7 7
Total Barrels of Oil Equivalent (MMBOE) 197 (1) 199 112 50 47
------- --- ------- ------- ------ -------
Average Daily Sales Volumes:
Gas (MMcf/d) 1,760 (8) 1,904 1,052 465 484
Oil and Condensate (MBbls/d) 205 10 186 98 40 30
NGLs (MBbls/d) 41 (2) 42 33 18 18
Total Barrels of Oil Equivalent (MBOE/d) 539 (1) 546 306 135 129
------- --- ------- ------- ------ -------
Oil Reserves (MMBbls) 1,131 -- 1,132 1,046 573 494
Gas Reserves (Tcf) 7.2 3 7.0 6.1 2.5 2.6
Total Reserves (MMBOE) 2,328 1 2,305 2,061 991 935
------- --- ------- ------- ------ -------
Worldwide Finding Cost ($/BOE)** $ 10.52 23 $ 8.53 $ 7.19 $ 4.87 $ 3.13
Worldwide Reserve Replacement
(% of Production) 112% (49) 221% 1,059% 213% 581%
Number of Employees 3,800 9 3,500 3,500 1,400 1,500
---------------------------------------------------------------------------------------------------------
|
* Consolidated for Anadarko Petroleum Corporation and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
** Worldwide finding costs are calculated by dividing worldwide costs incurred by the worldwide reserve additions, excluding sales in place.
Table of Measures Bcf -- Billion cubic feet MMBOE -- Million barrels of oil equivalent BOE -- Barrels of oil equivalent MMcf/d -- Million cubic feet per day MBbls/d -- Thousand barrels per day n/m -- Not meaningful MBOE/d -- Thousand barrels of oil equivalent per day Tcf -- Trillion cubic feet MMBbls -- Million barrels |
STOCKHOLDER INFORMATION
The common stock of Anadarko Petroleum Corporation is traded on the New York Stock Exchange. Average daily trading volume was 1,793,000 shares in 2002, 2,726,000 shares in 2001 and 1,618,000 shares in 2000. The ticker symbol for Anadarko is APC and the 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 2002 and 2001.
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
2002
Market Price
High $58.29 $58.01 $49.22 $49.92
Low $46.85 $46.86 $38.00 $42.13
Dividends $0.075 $0.075 $0.075 $0.100
2001
Market Price
High $72.99 $69.00 $59.75 $60.44
Low $54.63 $53.40 $44.05 $47.45
Dividends $0.050 $0.050 $0.050 $0.075
|
EXHIBIT 21
LIST OF SIGNIFICANT SUBSIDIARIES
Anadarko E&P Company, LP
a Delaware limited partnership,
Anadarko Holding Company
a Utah corporation,
Anadarko Canada Energy Ltd.
an Alberta, Canada corporation,
Anadarko Canada Corporation
an Alberta, Canada corporation,
Anadarko Land Corp.
a Nebraska corporation,
Anadarko Algeria Company, LLC
a Delaware limited liability company,
Anadarko Energy Services Company
a Delaware corporation,
APC Venezuela, S.R.L.
a Venezuela limited liability company,
Bitter Creek Coal Company
a Utah corporation
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
The Board of Directors
Anadarko Petroleum Corporation:
We consent to the incorporation by reference in the following registration statements of Anadarko Petroleum Corporation of our report dated January 31, 2003, with respect to the consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2002 and 2001, 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, 2002, which report appears in the December 31, 2002 annual report on Form 10-K of Anadarko Petroleum Corporation:
(a) Forms S-8 and S-3, Anadarko Employee Savings Plan (No. 33-8643).
(b) Forms S-8 and S-3, Anadarko Petroleum Corporation 1987 Stock Option Plan (No. 33-22134).
(c) Forms S-8 and S-3, Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors (No. 33-30384).
(d) Form S-8, Anadarko Petroleum Corporation 1993 Stock Incentive Plan (No. 33-54485).
(e) Form S-3, Anadarko Petroleum Corporation Dividend Reinvestment and Stock Purchase Plan (No. 333-65915, No. 333-88147 and No. 333-103102).
(f) Form S-8, Anadarko Petroleum Corporation 1998 Director Stock Incentive Plan (No. 333-78301).
(g) Form S-8, Anadarko Petroleum Corporation 1999 Stock Incentive Plan (No. 333-78303).
(h) Form S-3, Anadarko Petroleum Corporation Registration Statement for $650 million of Zero Yield Puttable Contingent Debt Securities (No. 333-60496).
(i) Form S-3, Anadarko Petroleum Corporation Registration Statement for $1 billion of Debt Securities, Preferred Stock, Depository Shares, Common Stock, Warrants, Purchase Contracts and Purchase Units (No. 333-86356).
Our report refers to changes in accounting for goodwill in 2002, derivative instruments in 2001, and foreign crude oil inventories in 2000.
/s/ KPMG LLP Houston, Texas March 13, 2003 |
EXHIBIT 23.2
EXPERT CONSENT
The Board of Directors
Anadarko Petroleum Corporation:
We consent to the inclusion in the Anadarko Petroleum Corporation annual report on Form 10-K for the year ended December 31, 2002 and the incorporation by reference in the following registration statements of Anadarko Petroleum Corporation of our report dated February 20, 2003, relating to the proved reserves status of the Marco Polo Discovery.
(a) Forms S-8 and S-3, Anadarko Employee Savings Plan (No. 33-8643).
(b) Forms S-8 and S-3, Anadarko Petroleum Corporation 1987 Stock Option Plan (No. 33-22134).
(c) Forms S-8 and S-3, Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors (No. 33-30384).
(d) Form S-8, Anadarko Petroleum Corporation 1993 Stock Incentive Plan (No. 33-54485).
(e) Form S-3, Anadarko Petroleum Corporation Dividend Reinvestment and Stock Purchase Plan (No. 333-65915, No. 333-88147 and No. 333-103102).
(f) Form S-8, Anadarko Petroleum Corporation 1998 Director Stock Incentive Plan (No. 333-78301).
(g) Form S-8, Anadarko Petroleum Corporation 1999 Stock Incentive Plan (No. 333-78303).
(h) Form S-3, Anadarko Petroleum Corporation Registration Statement for $650 million of Zero Yield Puttable Contingent Debt Securities (No. 333-60496).
(i) Form S-3, Anadarko Petroleum Corporation Registration Statement for $1 billion of Debt Securities, Preferred Stock, Depository Shares, Common Stock, Warrants, Purchase Contracts and Purchase Units (No. 333-86356).
/s/ Ryder Scott Company, L.P. Ryder Scott Company, L.P. Houston, Texas March 12, 2003 |
EXHIBIT 24
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS that the undersigned Director of ANADARKO PETROLEUM CORPORATION (the "Company"), a Delaware corporation, does hereby constitute and appoint MICHAEL E. ROSE, DIANE L. DICKEY, and SUZANNE SUTER, and each of them, his true and lawful attorney and agent to do any and all acts and things and execute any and all instruments which, with the advice of Counsel, said attorney and agent may deem necessary or advisable to enable the Company to comply with the Securities Act of 1934, as amended, and any rules, regulations and requirements of the Securities and Exchange Commission in connection with the filing under said Act of the Form 10-K Annual Report, including specifically, but without limitation thereof, to sign his name as a Director of the Company to the Form 10-K Annual Report filed with the Securities and Exchange Commission, and to any instrument or document filed as a part of, or in connection with, said Form 10-K Annual Report or amendment thereto; and the undersigned does hereby ratify and confirm all that said attorney and agent shall do or cause to be done by virtue thereof.
IN WITNESS WHEREOF, the undersigned have subscribed these presents this 13th day of March, 2003.
[ROBERT J. ALLISON, JR.] [CONRAD P. ALBERT]
----------------------------------- -------------------------------------
Robert J. Allison, Jr. Conrad P. Albert
[LARRY BARCUS] [RONALD BROWN]
----------------------------------- -------------------------------------
Larry Barcus Ronald Brown
[JAMES L. BRYAN] [JOHN R. BUTLER, JR.]
----------------------------------- -------------------------------------
James L. Bryan John R. Butler, Jr.
[PRESTON M. GEREN III] [JOHN R. GORDON]
----------------------------------- -------------------------------------
Preston M. Geren III John R. Gordon
[JOHN W. PODUSKA, SR.] [JOHN N. SEITZ]
----------------------------------- -------------------------------------
John W. Poduska, Sr. John N. Seitz
|
EXHIBIT 99.2
CERTIFICATION OF PERIODIC REPORT
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, John N. Seitz, President and Chief Executive Officer of Anadarko Petroleum Corporation (the "Company") and Michael E. Rose, Executive Vice President and Chief Financial Officer of the Company, certify that:
(1) the Annual Report on Form 10-K of the Company for the year ending December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.
March 13, 2003 /s/ John N. Seitz
-------------------
John N. Seitz
President and Chief Executive Officer
March 13, 2003 /s/ Michael E. Rose
-------------------
Michael E. Rose
Executive Vice President and Chief
Financial Officer
|
This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose.
(RYDER SCOTT COMPANY PETROLEUM CONSULTANTS LETTERHEAD)
EXHIBIT 99.3
February 20, 2003
Anadarko Petroleum Corporation
1201 Lake Robbins Drive
The Woodlands, Texas 77380
RE: Proved Reserves Status Marco Polo Discovery
Gentlemen:
Ryder Scott was asked by Anadarko Petroleum Corporation to perform an updated review of your internal oil and gas reserves studies of their Marco Polo Field (Green Canyon Block 608) located in federal waters offshore Louisiana. Ryder Scott's initial review of Marco Polo occurred in August 2002.
SCOPE OF ASSIGNMENT
The question Anadarko has asked is whether the technical data that was gathered and then used for these reserve studies is sufficient in quality and quantity to support an SEC Proved reserves classification. Our opinion, based upon our reserve work in over 2,000 Gulf of Mexico (GOM) blocks, is that the logs, cores, seismic and MDT data conclusively indicate high quality reservoir rocks and that this aggregated and complementary data is sufficient to form a "compelling case" to classify Marco Polo as having Proved reserves. Below is an outline of our general methodology for reserve analysis in the Gulf Coast / Gulf of Mexico and how the data in Marco Polo Field compares to our GOM database.
MARCO POLO DISCOVERY
DEEPWATER GULF OF MEXICO
ANADARKO PETROLEUM CORPORATION
Ryder Scott Company review - August 2002
RYDER SCOTT COMPANY REVIEW TEAM:
Ronald Harrell - CEO
John Hodgin - Exec VP & Chief Geologist
Joe Magoto - Sr. VP Reservoir Engineering & Head of Management Advisory services
Ryder Scott Company review - February 12, 2003
RYDER SCOTT COMPANY REVIEW TEAM:
Joe Magoto - Sr. VP Reservoir Engineering & Head of Management Advisory services
Anadarko Petroleum Corporation
February 20, 2003
GENERAL DISCUSSION ON RYDER SCOTT COMPANY RESERVES BOOKING
Key parameters used for typical Ryder Scott Company's (RSC) Gulf of Mexico (GOM) Analysis
1) Porosity from Logs
2) Porosity from side-wall Cores
3) Porosity & Permeability from whole Cores
4) Water saturation from open hole resistivity, Neutron-density, Gamma ray & SP logs
5) Hydrocarbon PVT fluid analysis obtained from multiple MDT's
6) Reservoir continuity from Log correlations
7) Reservoir continuity from MDT pressure analysis
8) Recovery Factors based on Aquifer size
9) Comparison of all above and to RSC data base in Miocene Gulf Coast sands
Ryder Scott Company approach to above parameters in approximate order of importance to the analysis.
1) Primary tool used - Log Analysis
a) Does the reservoir meet Porosity requirements for GOM based upon RSC data base
b) Does the reservoir meet Salt Water Saturation cutoff requirements for GOM
2) Core Analysis - Side-wall cores calibration of Porosity to Logs
3) Core Analysis - Whole core sometimes taken for increased certainty-more important in lower quality, higher shale content rock than present in subject field.
4) MDT tests - how we use the data:
a) Fluid samples for Hydrocarbon type and Oil quality including GOR.
b) Bottom hole pressure measurements
c) Multiple MDT pressures taken to establish pressure gradients with reservoir depths
1) Used between wells to establish reservoir continuity between updip and downdip wells
2) Used to estimate Oil/Water contacts in conjunction with Seismic data
5) DST or Conventional test through perforations after well completed-used in GOM primarily for Facility design or in shallow water (~ 50') where exploratory wells are saved to become producing wells. In that environment, tests have minimal additional costs or safety / EPA issues that are overriding problems in normal GOM shelf waters and especially deep water (> 400 meters).
SPECIFIC DISCUSSION OF ANADARKO'S MARCO POLO FIELD IN GULF OF MEXICO
Status of development @ August 2002: Status of Development @ February 2003: ------------------------------------ -------------------------------------- 4 Expendable open hole logged wells 4 Expendable open hole logged wells 4 Development wells 6 Development wells for production |
Anadarko Petroleum Corporation
February 20, 2003
Ryder Scott Company performed a limited review of Anadarko's Original-Oil-in-Place (OOIP). We had previously concluded that the structures are sufficiently well defined by the 4 Expendable wells and the 3-D Seismic data, and now in February 2003, 6 development wells have defined additional reserves. However, we have not performed an independent estimate of the pay counts nor constructed isopach maps. The sands are massive and clean enough that a visual inspection of the logs is sufficient for us to audit Anadarko's porosity and water saturations. After an additional audit of Anadarko's log analysis, we concluded that if RSC independently analyzed this field for official reserves certification, our porosity values would be approximately the same average as Anadarko's, which was 30 percent. This 30 percent average porosity (and permeability confirmed by whole cores) is sufficiently high that sands 50 to 100 feet thick typically flow 10,000 to 15,000 bopd. However Anadarko has used only 2,900 bopd per well for their SEC reserve forecast. It is our opinion, based upon both Darcy's Law flow rate calculations and analogies to other GOM fields, that the actual producing rates will be much higher.
We have taken Anadarko's reservoir parameters (see attached) and have independently calculated flow rates of 4,000 bopd for 50 foot sands and up to 8,000 bopd for 100 foot +/- sands using only 10 percent bottom hole pressure draw-down. Additionally based upon analogies, we would expect actual, possibly commingled flow rates to exceed 10,000 bopd. As part of our GOM database, we have had occasion to audit recently 2 of the nearest offset discoveries, which happen to be located in the same geologic basin. Those discoveries have porosities generally around 26 to 28 percent. Wells in those 2 discoveries are forecasted to flow at 15,000 to 17,000 bopd due to tubing restrictions, but potentially calculate as high as 30,000 bopd without restriction. Both of those discoveries have lower GOR's and less mobile oil than Marco Polo.
CONCLUSIONS
The 1978 SEC reserves definitions clearly state that "Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test". Other parts of the definitions relate to fluid contacts, pricing, costs and development status. Anadarko has not conducted any traditional flow tests in their evaluation of the Marco Polo Field but has acquired all of the information obtainable from a flow test through other more safe, cost effective and environmentally sensitive means. All of these techniques, which include advanced well log suites, core analyses and down-hole sampling and flow testing, represent proven technologies developed or advanced beyond those available in 1978.
After a careful review of the data provided by Anadarko, both raw and interpreted, we conclude that you have acquired the necessary information to support economic producibility without conducting the type of flow testing envisioned in 1978 and that you have effectively met the SEC reserves definitions in that regard. Attached is our comparison of multiple MDT testing versus a single conventional flow test that was presented at the October 2002 SPEE conference on SEC reserves definitions. From this table it can be clearly deduced there is an overwhelming amount of additional data gained from multiple MDT testing versus a single conventional flow test. It is our opinion that an extensive MDT testing program provides a more compelling case of reasonable certainty for proved reserves than a single conventional flow test.
Furthermore, our internal industry survey in October 2002 indicated only 6 out of 45 fields or 13 percent have been traditionally flow tested in the deepwater Gulf of Mexico. It is also our experience that the practice of conducting a traditional flow test in the U.S. Gulf Coast and the Gulf of Mexico is limited to those circumstances where down-hole data are (1) not sufficiently conclusive to meet the "economic producibility" required or (2) where a level of refinement is needed in designing facilities to meet the expected rates of flow.
Anadarko Petroleum Corporation
February 20, 2003
CONSENT
Anadarko is authorized to incorporate this letter in its required financial reporting or in communications with the U.S. SEC as long as the entire letter report is used. We would grant our consent for Anadarko to use selected portions of this report only upon specific review of the passages sought to be included. This consent is being granted for a limited time period not to exceed approximately 90 days from the effective date of this report.
RYDER SCOTT COMPANY, L.P.
/s/ Ronald Harrell
-----------------------------------
Ronald Harrell, P.E.
Chairman and CEO
DRH/sw
|
MARCO POLO DISCOVERY
DEEPWATER GULF OF MEXICO
ANADARKO PETROLEUM CORPORATION
RYDER SCOTT COMPANY FLOW RATE CALCULATIONS - AUGUST 2002
ROCK DATA
Porosity 29.9 %
Permeability - k 215 md
Water saturation - Sw 32.9 %
RESERVOIR DATA
Pressure - BHP initial 7433 psia
Temperature - reservoir 121 F
Pay -average net feet 113 feet
FLUID PROPERTIES
Oil gravity - API 32
Solution Gas GOR 920 scf / bbl
viscosity 1.2 cp
bubble point 2750 #
PRODUCING CONDITIONS
Drawdown ~ 10% 750
skin factor gravel-packed 2
-----
CALCULATED INITIAL RATE 8,200 bopd
-----
|
MDT MULTIPLE TESTS VS. ACTUAL PERFORATION / DST TESTS
FEBRUARY 18, 2003
MDT TOOL
-----------------------------------------------------------------
TYPE OF MEASUREMENT ADVANTAGES DISADVANTAGES
------------------- ------------------------------- ------------------------------
Drawdown & commercial rate multiple depth contributions limited sample size
measured
Permeability measurements multiple depth mobilities (k) shorter / limited time of test
can capture foot by foot in the past with older tools
hetrogenity (see Future Trends)
Pressure measurements multiple depth tests reveal
actual fluid gradients, I.e. gas
vs. Oil vs. Water (validates
some PVT data)
fluid gradients at depth can
define and confirm Gas/water or
Oil/Water contacts
Industry now determining Cond
yields from press gradients
EXTENT OF FLOW DATA
Multiple zone tests In one pass, can take 50 +/-
tests which usually covers many
individual pays
Multiple well tests across the MDT costs low enough to run tool
structure in most, if not all wells.
Provides continuity between
wells validating the size of
area that is productive
FUTURE TRENDS
Maxi-MDT tool and bypass flow
before fluid sample capture
approximate longer time actual
prod tests
PROD. TEST - PERF OR DST
-------------------------------------------------------------------------
TYPE OF MEASUREMENT ADVANTAGES DISADVANTAGES
------------------- --------------------------------- -------------------------------------
Drawdown & commercial rate fluid to surface producing DST test not representative of
charteristics measured completed well with typical gravel
pack but skin damage
Permeability measurements longer drawdown period (perceived) only average Permeability (k)
measured over the perforation / DST
test interval
Pressure measurements long term buildups could multiple $$$ million dollar costs &
conceptually be possible, but at EPA / MMS environmental risks
prohibitively high costs & lack
of storage (especially for Oil)
EXTENT OF FLOW DATA
Multiple zone tests Good comparison of actual Costs are so high for one DST, or
flowrates between different especially perforation tests, that
quality rocks only 1 or 2 zones are usually
tested.
Multiple well tests across the -------------- High costs that typically range
structure from $5 - 15MM limits this type of
test to almost always a single well.
FUTURE TRENDS
-------------- EPA requirements and increased
pressures on Oil industry in
general increasing rapidly, making
future risks of Oil spills or
incomplete burn even more
politically difficult.
|