UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarter Ended September 30, 2003
Commission File No. 1-8968
ANADARKO PETROLEUM CORPORATION
|
Incorporated in the |
Employer Identification |
|
State of Delaware |
No. 76-0146568 |
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 whether the registrant is an accelerated filer. Yes X No _____.
The number of shares outstanding of the Company's common stock as of October 31, 2003 is shown below:
|
Title of Class |
Number of Shares Outstanding |
|
Common Stock, par value $0.10 per share |
250,898,099 |
ANADARKO PETROLEUM CORPORATION
(Unaudited)
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.
The information, as furnished herein, reflects all normal recurring adjustments that are, in the opinion of Management, necessary for a fair statement of financial position as of September 30, 2003 and December 31, 2002, the results of operations for the three and nine months ended September 30, 2003 and 2002 and cash flows for the nine months ended September 30, 2003 and 2002. 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 In 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," which 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. See
Note 3 .
In 2003, the Company adopted the fair value method of accounting for stock-based employee compensation using the prospective method described in SFAS No. 148, "Accounting for Stock-Based Compensation--Transition and Disclosure." See
Note 2 .
Beginning with the second quarter of 2003, the Company included derivative contracts that qualify as cash flow hedges in the ceiling test calculation in accordance with a revision to Staff Accounting Bulletin Topic 12, "Oil and Gas Producing Activities."
The Company adopted SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," in 2003. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities that fall within the scope of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 had no impact on the Company's financial statements.
Derivative Instruments 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 derivative contracts that are not normal sales contracts are carried on the balance sheet at fair value. Realized gains and losses are recognized in sales when the underlying physical oil and gas production is sold. Accordingly, realized derivative gains and losses are generally offset by similar changes in the realized value of the underlying physical oil and gas 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.
If the hedged exposure is a cash flow exposure, the effective portion of the unrealized 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, is recognized currently in other (income) expense.
Unrealized gains and losses on derivative instruments that do not meet the conditions to qualify for hedge accounting are recognized in gas sales and oil sales. In the third quarter of 2003, these amounts for prior periods were reclassified from other (income) expense to gas sales and oil sales. The amount of the reclassification was not significant and had no effect on net income or per share amounts.
Derivative instruments, including both physical delivery and financially settled purchase and sale contracts, utilized in the Company's energy trading activities are accounted for under the mark-to-market accounting method pursuant to SFAS No. 133. Under this method, the derivatives 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. The Company's firm transportation keep-whole agreement and the derivative financial instruments used in the management of the price risk associated with the keep-whole agreement are also accounted for under the mark-to-market accounting method pursuant to SFAS No. 133.
The Company's derivative instruments 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 7 .
Earnings Per Share The Company's basic earnings 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 9 .
New Accounting Principles and Recent Developments Financial Accounting Standards Board Interpretation (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 fourth quarter 2003. During the second quarter of 2003, two of the Company's corporate office buildings located in The Woodlands, Texas, were acquired by a wholly-owned subsidiary of a major financial institution from the special purpose entities that had leased the buildings to the Company. The new lessor is not a variable interest entity. See
Note 14 . The Company believes the adoption of FIN No. 46 will have no impact on the Company's financial statements.
The Financial Accounting Standards Board (FASB) is expected to consider whether or not oil and gas drilling rights acquired should be classified as an intangible asset pursuant to SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Anadarko classifies the cost of oil and gas mineral rights as properties and equipment and believes that this is consistent with oil and gas accounting and industry practice. If the FASB determines that oil and gas drilling rights acquired are intangible assets pursuant to SFAS Nos. 141 and 142, these costs would be reclassified from properties and equipment to intangible assets on the balance sheet. There would be no effect on the statement of income or cash flows.
2. Stock-Based Compensation SFAS No. 123, "Accounting for Stock-Based Compensation," defines a fair value method of accounting for an employee stock option or similar equity instrument. SFAS No. 123 allows an entity to continue measuring compensation costs for these instruments using Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." In 2003, the Company voluntarily changed to the fair value method of accounting for stock-based employee compensation for all grants after January 1, 2003 using the prospective method described in SFAS No. 148. Anadarko applies APB Opinion No. 25 for prior grants 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 all stock option grants had been determined using the fair value method, the Company's net income and EPS would have been as shown in the pro forma amounts below:
Three Months Ended
Nine Months Ended
September 30
September 30
millions except per share amounts
2003
2002
2003
2002
Net income available before effect of change
in accounting principle as reported
$
274
$
189
$
946
$
516
Add: Stock-based employee compensation expense included
in net income, after taxes
4
2
9
7
Deduct: Total stock-based employee compensation expense
determined under the fair value method, after taxes
(9
)
(6
)
(25
)
(26
)
Pro forma net income before change in accounting principle
$
269
$
185
$
930
$
497
Basic EPS -- as reported before change in accounting principle
$
1.09
$
0.76
$
3.79
$
2.08
Basic EPS -- pro forma before change in accounting principle
$
1.08
$
0.74
$
3.73
$
2.00
Diluted EPS -- as reported before change in accounting principle
$
1.09
$
0.74
$
3.74
$
2.01
Diluted EPS -- pro forma before change in accounting principle
$
1.07
$
0.73
$
3.68
$
1.94
The following table provides a rollforward of the asset retirement obligations for the current year:
|
millions |
||||||||
|
Carrying amount of asset retirement obligations as of January 1, 2003 |
$ |
278 |
||||||
|
Liabilities incurred during 2003 |
105 |
|||||||
|
Liabilities settled during 2003 |
(11 |
) |
||||||
|
Accretion expense |
15 |
|||||||
|
Revisions in estimated liabilities |
13 |
|||||||
|
|
|
|
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|
||
|
Carrying amount of asset retirement obligations as of September 30, 2003 |
$ |
400 |
||||||
|
|
|
|
|
|
|
|
||
The following table shows the effect of the implementation on the Company's net income and EPS as if SFAS No. 143 had been in effect in prior periods. There was no material effect on reported amounts for the three and nine months ended September 30, 2002.
|
Years Ended December 31 |
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millions except per share amounts |
2002 |
2001 |
2000 |
1999 |
1998 |
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Actual |
||||||||||||||||
|
Net income (loss) available before effect of |
||||||||||||||||
|
change in accounting principle |
$ |
825 |
$ |
(183 |
) |
$ |
813 |
$ |
32 |
$ |
(49 |
) |
||||
|
Basic EPS -- before change in accounting principle |
$ |
3.32 |
$ |
(0.73 |
) |
$ |
4.42 |
$ |
0.25 |
$ |
(0.41 |
) |
||||
|
Diluted EPS -- before change in accounting principle |
$ |
3.21 |
$ |
(0.73 |
) |
$ |
4.25 |
$ |
0.25 |
$ |
(0.41 |
) |
||||
|
Pro forma amounts assuming SFAS No. 143 was |
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|
|
|
|
applied retroactively |
||||||||||||||||
|
Net income (loss) available before effect of |
||||||||||||||||
|
change in accounting principle |
$ |
826 |
$ |
(178 |
) |
$ |
812 |
$ |
33 |
$ |
(48 |
) |
||||
|
Basic EPS -- before change in accounting principle |
$ |
3.32 |
$ |
(0.71 |
) |
$ |
4.41 |
$ |
0.26 |
$ |
(0.40 |
) |
||||
|
Diluted EPS -- before change in accounting principle |
$ |
3.21 |
$ |
(0.71 |
) |
$ |
4.24 |
$ |
0.26 |
$ |
(0.40 |
) |
||||
|
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|
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|
Carrying amount of asset retirement obligations |
||||||||||||||||
|
Beginning of year |
$ |
251 |
|
$ |
208 |
|
$ |
48 |
|
$ |
44 |
|
$ |
36 |
|
|
|
End of year |
$ |
278 |
|
$ |
251 |
|
$ |
208 |
|
$ |
48 |
|
$ |
44 |
|
|
4. Inventories Inventories are stated at the lower of average cost or market. The major classes of inventories, which are included in other current assets, are as follows:
September 30,
December 31,
millions
2003
2002
Materials and supplies
$
77
$
75
Natural gas
36
16
Crude oil
13
15
NGLs
1
--
Total
$
127
$
106
5. Properties and Equipment
Oil and gas properties include costs of $2.7 billion and $3.1 billion at September 30, 2003 and December 31, 2002, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unevaluated properties and major development projects. At September 30, 2003 and December 31, 2002, the Company's investment in countries where reserves have not been established was $74 million and $63 million, respectively.
During the nine months ended September 30, 2003 and 2002, the Company made provisions for impairments of oil and gas properties of $92 million and $33 million, respectively. The 2003 provisions for impairments include $68 million related to a third quarter ceiling test impairment of oil and gas properties in Qatar as a result of lower future production estimates and unsuccessful exploration activities and $24 million related primarily to unsuccessful exploration activities in Australia, Gabon, Tunisia and Angola. Impairments in 2002 of $33 million related primarily to activities in Congo, Oman and Australia.
Total interest costs incurred during the third quarter of 2003 and 2002 were $89 million and $91 million, respectively. Of these amounts, the Company capitalized $30 million and $42 million during the third quarter of 2003 and 2002, respectively. Total interest costs incurred during the first nine months of 2003 and 2002 were $281 million and $267 million, respectively. Of these amounts, the Company capitalized $94 million and $121 million during the first nine months of 2003 and 2002, 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 $45 million and $48 million during the third quarter of 2003 and 2002, respectively. For the first nine months of 2003 and 2002, the Company capitalized internal costs of $142 million and $148 million, 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.
6. Debt
A summary of debt follows:
September 30, 2003
December 31, 2002
millions
Principal
Carrying Value
Principal
Carrying Value
Notes Payable, Banks
$
135
$
135
$
44
$
44
Commercial Paper
170
170
181
181
Long-term Portion of Capital Lease
5
5
7
7
6 3/4% Notes due 2003
--
--
73
73
5 7/8% Notes due 2003
83
83
83
83
6.5% Notes due 2005
170
167
170
166
7.375% Debentures due 2006
88
88
88
87
7% Notes due 2006
174
171
174
171
5 3/8% Notes due 2007
650
647
650
647
3.25% Notes due 2008
350
349
--
--
6.75% Notes due 2008
116
111
116
111
7.8% Debentures due 2008
11
11
11
11
7.3% Notes due 2009
85
83
85
83
6 3/4% Notes due 2011
950
911
950
912
6 1/8% Notes due 2012
400
395
400
395
5% Notes due 2012
300
298
300
297
7.05% Debentures due 2018
114
105
114
105
Zero Coupon Convertible
Debentures due 2020
--
--
380
380
Zero Yield Puttable Contingent
Debt Securities due 2021
30
30
30
30
7.5% Debentures due 2026
112
106
112
106
7% Debentures due 2027
54
54
54
54
6.625% Debentures due 2028
17
17
17
17
7.15% Debentures due 2028
235
213
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
7.5% Debentures due 2096
83
75
83
75
7 1/4% Debentures due 2096
49
49
49
49
Total debt
$
5,594
5,448
$
5,619
5,471
Less current portion
277
300
Total long-term debt
$
5,171
$
5,171
At September 30, 2003, $418 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," $141 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 April 2003, Anadarko redeemed for cash its callable Zero Coupon Convertible Debentures due 2020. Anadarko funded the $384 million redemption with available credit facilities that carry a lower effective interest rate. Anadarko paid $556.46 per debenture, reflecting the issue price plus accrued interest at 3.5%.
In May 2003, the Company issued $350 million principal amount of 3.25% Notes due 2008. The net proceeds from this issuance were used to reduce floating interest rate debt that was incurred in April 2003 to redeem the Zero Coupon Convertible Debentures due 2020.
In October 2003, the Company terminated its existing revolving credit agreements and entered into a $750 million 364-Day Revolving Credit Agreement with a syndicate of U.S. and Canadian lenders. The agreement terminates in October 2004 or October 2005, if any loan under the agreement is converted to a term loan.
Commodity Derivative Instruments
The Company is exposed to price risk from changing commodity prices. Management believes it is prudent to periodically 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 financial 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 derivative financial instruments utilized by the Company include options, futures and swaps.
The Company also enters into commodity derivative financial instruments (options, futures and swaps) and physical delivery contracts for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. These 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 may use options and swaps 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 gas sales and oil sales at major industry trading locations; e.g., Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Swap agreements are generally used to fix or float the price of oil and gas at major trading locations. Basis swaps are used to fix the price differential between the price of gas at Henry Hub and various other market locations. Physical delivery purchase and sale agreements require the receipt or delivery of physical product at a specified location and price. The pricing can be fixed or market-based. Options are generally used to fix a floor and a ceiling price (collar) for the Company's expected future gas sales and oil sales. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap, over-the-counter traded option and physical delivery agreements expose the Company to credit risk to the extent the counter-party is unable to meet its settlement commitment. The Company 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 and option counter-parties.
Cash Flow Hedges At September 30, 2003 and December 31, 2002, the Company had option contracts, swap contracts and fixed price physical delivery contracts in place to hedge a portion of expected future sales of equity oil and gas production. The fixed price physical delivery contracts are excluded from hedge accounting treatment under the normal purchase, normal sale provision. The derivative financial instruments receive hedge accounting treatment if they meet the qualifications and mark-to-market accounting is applied to those that do not qualify for hedge accounting. The fair values and the accumulated other comprehensive income balances applicable to the derivative financial instruments are as follows:
September 30,
December 31,
millions
2003
2002
Fair Value -- Asset (Liability)
Current
$
(142
)
$
(115
)
Non-current
(37
)
(39
)
Total
$
(179
)
$
(154
)
Accumulated other comprehensive income (loss) before taxes
$
(134
)
$
(128
)
Accumulated other comprehensive income (loss) after taxes
$
(85
)
$
(81
)
The difference between the fair values 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.
As of September 30, 2003, the Company had the following cash flow hedges through 2005 related to its oil and gas producing activities (non-trading activities). There are no significant cash flow hedges beyond 2005.
Fourth
Quarter
Annual
2003
2004
2005
Natural Gas
Three-Way Collars (thousand MMBtu/d)
399
269
19
NYMEX price per MMBtu
Floor sold price
$
2.91
$
2.67
$
2.20
Floor purchased price
$
3.97
$
3.65
$
3.00
Ceiling sold price
$
5.01
$
5.30
$
4.83
Two-Way Collars (thousand MMBtu/d)
61
44
26
NYMEX price per MMBtu
Floor purchased price
$
4.79
$
4.29
$
3.76
Ceiling sold price
$
8.73
$
6.43
$
5.65
Fixed Price (thousand MMBtu/d)
495
259
33
NYMEX price per MMBtu
$
4.28
$
3.72
$
3.00
Total (thousand MMBtu/d)
955
572
78
Basis Swaps (thousand MMBtu/d)
695
138
20
Price per MMBtu
$
(0.21
)
$
(0.06
)
$
(0.09
)
MMBtu -- million British thermal units
MMBtu/d -- million British thermal units per day
|
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Fourth |
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Quarter |
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Annual |
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2003 |
|
|
|
2004 |
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|
2005 |
|
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|
Crude Oil |
|
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|
|
|
|
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||||
|
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|
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|
|
|
|
||||
|
Three-Way Collars (MBbls/d) |
|
|
|
|
53 |
|
|
20 |
|
|
-- |
|
||||
|
NYMEX price per barrel |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Floor sold price |
|
|
|
$ |
18.62 |
|
$ |
18.00 |
|
$ |
-- |
|
||||
|
Floor purchased price |
|
|
|
$ |
23.81 |
|
$ |
22.00 |
|
$ |
-- |
|
||||
|
Ceiling sold price |
|
|
|
$ |
27.39 |
|
$ |
28.07 |
|
$ |
-- |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Two-Way Collars (MBbls/d) |
|
|
|
|
4 |
|
|
3 |
|
|
2 |
|
||||
|
NYMEX price per barrel |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Floor purchased price |
|
|
|
$ |
25.00 |
|
$ |
22.00 |
|
$ |
22.00 |
|
||||
|
Ceiling sold price |
|
|
|
$ |
28.29 |
|
$ |
26.32 |
|
$ |
26.32 |
|
||||
|
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|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Fixed Price (MBbls/d) |
|
|
|
|
14 |
|
|
8 |
|
|
-- |
|
||||
|
NYMEX price per barrel |
|
|
|
$ |
25.39 |
|
$ |
23.09 |
|
$ |
-- |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Total (MBbls/d) |
|
|
|
|
71 |
|
|
31 |
|
|
2 |
|
||||
|
|
|
|
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||||
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||||
|
MBbls/d -- thousand barrels per day |
|
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A two-way collar is a combination of options, a sold call and 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 three-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. The fixed price hedges consist of swaps and physical delivery contracts and establish a fixed price the Company will receive for the volumes under contract.
Marketing and Trading Activities
The fair values of the Company's marketing and trading portfolio (both physical delivery and financially settled contracts) as of September 30, 2003 and December 31, 2002 are as follows:
September 30,
December 31,
millions
2003
2002
Fair Value -- Asset (Liability)
Current
$
6
$
(5
)
Non-current
5
--
Total
$
11
$
(5
)
Firm Transportation Keep-Whole Agreement
A company Anadarko acquired in 2000 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 long-term firm 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 pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko 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 the market value of firm transportation, they also limit the potential to benefit from increases in the market value of firm transportation. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward twelve months. Net (payments to) or receipts from Duke for the three months ended September 30, 2003 and 2002 were $(4) million and $12 million, respectively, and for the nine months ended September 30, 2003 and 2002 net receipts from Duke were $19 million and zero, 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 the firm transportation capacity to determine if the estimated fair value should be adjusted. The Company recognized other expense of $8 million and other income of $19 million for the three months ended September 30, 2003 and 2002, respectively, and other income of $10 million and $28 million for the nine months ended September 30, 2003 and 2002, respectively, related to the keep-whole agreement and associated derivative instruments. As of September 30, 2003 and December 31, 2002, accounts payable included $29 million and $5 million and other long-term liabilities included $53 million and $68 million, respectively, related to the keep-whole agreement and associated derivative instruments.
Anticipated undiscounted and discounted liabilities for the firm transportation keep-whole agreement at September 30, 2003 are as follows:
millions
Undiscounted
Discounted
2003
$
12
$
12
2004
23
22
2005
20
17
2006
19
15
2007
14
10
Later years
9
6
Total
$
97
$
82
8. Preferred Stock For the first, second and third quarters of 2003 and 2002, dividends of $13.65 per share (equivalent to $1.365 per Depositary Share) were paid to holders of preferred stock. During the first quarter of 2003, the Company repurchased $12 million of preferred stock.
9. Common Stock The Company's credit agreements allow for a maximum capitalization ratio of 60% debt exclusive of the effect of any non-cash writedowns. While there is no specific restriction on paying dividends, under the maximum debt capitalization ratio retained earnings were not restricted as to the payment of dividends at September 30, 2003 and December 31, 2002.
The reconciliation between basic and diluted EPS is as follows:
Three Months Ended
Three Months Ended
September 30, 2003
September 30, 2002
Per Share
Per Share
millions except per share amounts
Income
Shares
Amount
Income
Shares
Amount
Basic EPS
Net income available before change
in accounting principle
$
274
250
$
1.09
$
189
249
$
0.76
Effect of convertible debentures
and ZYP-CODES
--
--
2
8
Effect of dilutive stock options,
performance-based stock awards
and common stock put options
--
1
--
1
Diluted EPS
Net income available before change
in accounting principle plus
assumed conversion
$
274
251
$
1.09
$
191
258
$
0.74
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Nine Months Ended |
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Nine Months Ended |
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September 30, 2003 |
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September 30, 2002 |
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Per Share |
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Per Share |
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millions except per share amounts |
Income |
Shares |
Amount |
Income |
Shares |
Amount |
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Basic EPS |
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Net income available before change |
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in accounting principle |
$ |
946 |
|
|
249 |
|
$ |
3.79 |
|
$ |
516 |
|
|
248 |
|
$ |
2.08 |
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Effect of convertible debentures |
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and ZYP-CODES |
|
3 |
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4 |
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6 |
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10 |
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Effect of dilutive stock options, |
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performance-based stock awards |
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and common stock put options |
|
-- |
|
|
1 |
|
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-- |
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2 |
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Diluted EPS |
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Net income available before change |
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in accounting principle plus |
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|
assumed conversion |
$ |
949 |
|
|
254 |
|
$ |
3.74 |
|
$ |
522 |
|
|
260 |
|
$ |
2.01 |
|
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For the three and nine months ended September 30, 2003, options for 8.5 million and 8.8 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because the options' exercise price was greater than the average market price of common stock for the periods. For the three and nine months ended September 30, 2002, options for 8.9 million and 3.9 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because the options' exercise price was greater than the average market price of common stock for the periods. For the three and nine months ended September 30, 2002, put options for zero and 0.7 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.
10. Statements of Cash Flows Supplemental Information The amounts of cash paid (received) for interest (net of amounts capitalized) and income taxes are as follows:
Nine Months Ended
September 30
millions
2003
2002
Interest
$
169
$
103
Income taxes
$
89
$
(50
)
11. Segment Information The following table illustrates information related to Anadarko's business segments. The segment shown as Intercompany Eliminations and All Other includes other smaller operating units, corporate activities, financing activities and intercompany eliminations.
Oil and Gas
Marketing
Intercompany
Exploration
and
Eliminations
millions
and Production
Trading
Minerals
and All Other
Total
Three Months Ended September 30:
2003
Revenues
$
761
$
50
$
5
$
524
$
1,340
Intersegment revenues
522
3
--
(525
)
--
Total revenues
1,283
53
5
(1
)
1,340
Impairments related to oil and gas properties
74
--
--
--
74
Restructuring costs
14
--
--
19
33
Income (loss) before income taxes
$
591
$
14
$
5
$
(131
)
$
479
2002
Revenues
$
591
$
35
$
11
$
301
$
938
Intersegment revenues
299
2
--
(301
)
--
Total revenues
890
37
11
--
938
Income (loss) before income taxes
$
405
$
15
$
10
$
(125
)
$
305
Nine Months Ended September 30:
2003
Revenues
$
2,206
$
105
$
22
$
1,511
$
3,844
Intersegment revenues
1,504
11
--
(1,515
)
--
Total revenues
3,710
116
22
(4
)
3,844
Impairments related to oil and gas properties
92
--
--
--
92
Restructuring costs
14
--
--
19
33
Income (loss) before income taxes
$
1,905
$
29
$
19
$
(402
)
$
1,551
Net properties and equipment
$
15,125
$
249
$
1,200
$
439
$
17,013
Goodwill
$
1,473
$
--
$
--
$
--
$
1,473
2002
Revenues
$
1,743
$
93
$
33
$
861
$
2,730
Intersegment revenues
851
6
--
(857
)
--
Total revenues
2,594
99
33
4
2,730
Impairments related to oil and gas properties
33
--
--
--
33
Income (loss) before income taxes
$
1,087
$
20
$
29
$
(362
)
$
774
Net properties and equipment
$
12,701
$
236
$
1,204
$
431
$
14,572
Goodwill
$
1,433
$
--
$
--
$
--
$
1,433
The following table summarizes the Company's restructuring costs. Activity for the three months ended September 30, 2003 also represents the cumulative amounts.
Three Months
Ended
Total Expected
September 30,
millions
Costs
2003
Costs by category
One-time termination benefits
$
29
$
28
Contract termination costs
3
3
Other
4
2
Total
$
36
$
33
Costs by segment
Corporate
$
21
$
19
Oil and Gas Exploration and Production
15
14
Total
$
36
$
33
The following table is a reconciliation of the beginning and ending restructuring costs liability balances. The majority of the remaining restructuring costs liability at September 30, 2003 is related to one-time termination benefits.
millions
Restructuring costs liability as of July 1, 2003
$
--
Costs incurred during the period
33
Cash payments during the period
(24
)
Restructuring costs liability as of September 30, 2003
$
9
13. Other (Income) Expense Other (income) expense consists of the following:
|
Three Months Ended |
Nine Months Ended |
||||||||||||||||
|
|
|
September 30 |
|
|
September 30 |
|
|||||||||||
|
|
|
|
|
|
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|
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|
millions |
|
2003 |
|
|
2002 |
|
|
2003 |
|
|
2002 |
|
|||||
|
|
|
|
|
|
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|
|||||
|
Firm transportation keep-whole contract valuation (See Note 7 ) |
$ |
8 |
$ |
(19 |
) |
$ |
(10 |
) |
$ |
(28 |
) |
||||||
|
Ineffectiveness of derivative financial instruments |
(6 |
) |
2 |
(3 |
) |
10 |
|||||||||||
|
Foreign currency exchange * |
(1 |
) |
13 |
(15 |
) |
4 |
|||||||||||
|
Gas sales contracts - accretion of discount |
1 |
3 |
5 |
7 |
|||||||||||||
|
Other |
|
-- |
|
|
(3 |
) |
|
(2 |
) |
|
5 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Total |
$ |
2 |
$ |
(4 |
) |
$ |
(25 |
) |
$ |
(2 |
) |
||||||
|
|
|
|
|
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|
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|
*The three and nine months ended September 30, 2003 exclude zero and $8 million, respectively, in transaction losses related to remeasurement of the Venezuela deferred tax liability. The three and nine months ended September 30, 2002 exclude $3 million and $36 million, respectively, in transaction gains related primarily to remeasurement of the Venezuela deferred tax liability. These amounts are included in income tax expense. |
|||||||||||||||||
Financial Operating Leases
During the second quarter of 2003, two of the Company's corporate office buildings located in The Woodlands, Texas, were acquired by a wholly-owned subsidiary of a major financial institution from the special purpose entities that had leased the buildings to the Company. The original leases were amended and restated, and, other than the extension of the period of the lease, the terms of the replacement lease between the Company and the real estate development company were essentially unchanged. The total amount funded under the new lease was approximately $214 million. The Company has accounted for this arrangement as an operating lease.
The lease term is seven years and the monthly lease payments are based on the London interbank borrowing rate applied against the lease balance. The lease contains various covenants including covenants regarding the Company's financial condition. Default under the lease, including violation of these covenants, could require the Company to purchase the facilities for a specified amount, which approximates the lessor's original cost of $214 million. As of September 30, 2003, 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 assist the lessor in the sale of the properties. The Company has provided a residual value guarantee for any deficiency of up to $187 million if the properties are sold for less than the lease balance. In addition, the Company is entitled to any proceeds from a sale of the properties in excess of the lease balance.
The Company has an $8 million liability and corresponding prepaid rent asset as of September 30, 2003 related to its residual value guarantee on the corporate office buildings. If 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 lease balance, the liability will be adjusted accordingly. Currently, Management does not believe it is probable that the fair market value of the properties will be less than the lease balance at the end of the lease term.
Production Platform In 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. The agreement does not contain any purchase options, purchase obligations or value guarantees.
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 a company Anadarko acquired by merger in 2000 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 The Company is subject to various claims from its royalty owners in the regular course of its business as an oil and gas producer, including disputes regarding measurement, costs and expenses beyond the wellhead and basis valuations. Among such claims, 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 September 2000 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. The defendants expected a hearing in the third quarter of 2003; however, the Wyoming federal judge has suggested that the case be remanded back to the Texas federal court, which will delay the proceedings.
A group of royalty owners purporting to represent Anadarko's gas royalty owners in Texas was granted class action certification styled Neinast, Russell, et al. v. Union Pacific Resources Company, et al . 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 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 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 styled 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 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.
A royalty owner action styled Texas Osage Royalty Pool, Inc. v. UPRG, Inc., UP Fuels, Inc., et al . filed in January 1997 in the 335th District Court of Lee County, Texas became active during the first quarter of 2003. The case involves allegations that a company Anadarko acquired by merger in 2000, UPRG, Inc., failed to properly pay royalties due Texas Osage. In addition, the plaintiff contends that the Company failed to comply with express and implied provisions of various leases between April 1993 and the present. The Company is vigorously contesting the claims and believes royalties were properly paid based upon prices received in sales made to third-party purchasers or at sales prices comparable to third-party sales. The plaintiff served expert reports in the third quarter of 2003, which calculate the plaintiff's royalty damages in a range between $2 million and $5 million. The plaintiff also claims additional damages with regard to certain specific land issues that are not material. The trial court has postponed the trial date until an indefinite date sometime after April 2004.
CITGO Litigation CITGO Petroleum Corporation's (CITGO) claims arise out of an Asset Purchase and Contribution Agreement in 1987 whereby a company Anadarko acquired by merger in 2000 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 eventually entered into a settlement agreement to allocate, on an interim basis, each party's liability for defense and liability costs 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 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. Negotiations and discussions with CITGO continue. Anadarko 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.
In 2001, the Company paid $15 million for settlement of the liability for Kansas ad valorem tax reimbursements for the interstate portion of this matter. The remaining dispute between the Company and PanEnergy is attributable to the Cimmaron River System (CRS). The Company filed a settlement agreement, which has been approved, in the CRS matter during January 2003. The Company paid approximately $5 million under the CRS settlement agreement during the second quarter of 2003. Anadarko's net income for 2001 included a $20 million charge (before taxes) related to these settlement agreements.
Other Litigation The Company has a reserve of about $2 million for Kansas ad valorem tax refunds. The Company has reached agreements in principle to settle two of the three remaining claims, and expects to conclude those settlements by paying the sum of $2 million in the fourth quarter of 2003. Upon conclusion of those settlements, the Company will be subject to one outstanding claim for a principle refund amount of less than $1 million; however, based upon a prior release the Company obtained from this claimant, the Company intends to vigorously defend this one remaining claim. A final hearing is scheduled for January 2004.
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 a company Anadarko acquired by merger in 2000 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 and the lessor are currently in the process of determining the current fair market rental and fair market sales value of the West Plant and expect the determination will be completed by year-end 2003. Based on the information currently available, no liability has been recognized as of September 30, 2003.
Guarantees Anadarko is guarantor for certain obligations of its wholly-owned and consolidated subsidiaries, which are included in the consolidated financial statements and notes. The Company also has made residual value guarantees in connection with aircraft operating leases for any deficiency if the aircraft are sold for less than the maximum lessee risk amount of approximately $15 million. No liability has been recorded related to these guarantees.
The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity, which is not a consolidated subsidiary, is 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, environmental and surety bonds. The Company's guarantee under the revolving credit agreement expires in 2005 coinciding with the maturity of that agreement. The Company's guarantees under the letters of credit securing the industrial revenue, environmental and surety bonds expire in 2004; however, these letters of credit and the related guarantees are expected to be extended or to continue until the maturity dates of the obligations which range from 2005 to 2018. The amounts the Company would be obligated to pay should the affiliate default on these obligations would be up to $15 million for the revolving credit agreement, $8 million for environmental and surety bonds and $15 million for the industrial revenue bonds. No liability has been recognized for these guarantees.
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. These losses have been disallowed by the taxing authorities. The Company has filed a lawsuit seeking relief. The Company believes it is probable that these losses will have to be settled with the purchaser in cash. The Company has a $21 million liability recorded for the contingency.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
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 elsewhere in this Form 10-Q 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. See "Regulatory Matters and Additional Factors Affecting Business" and "Critical Accounting Policies" in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's 2002 Annual Report on Form 10-K.
Financial Results
|
Selected Financial Data |
||||||||||||||||
|
Three Months Ended |
Nine Months Ended |
|||||||||||||||
|
|
|
September 30 |
|
|
September 30 |
|
||||||||||
|
|
|
|
|
|
|
|
||||||||||
|
millions except per share amounts |
2003 |
2002 |
2003 |
2002 |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Revenues |
$ |
1,340 |
$ |
938 |
$ |
3,844 |
$ |
2,730 |
||||||||
|
Costs and expenses |
$ |
800 |
$ |
588 |
$ |
2,131 |
$ |
1,812 |
||||||||
|
Interest expense |
$ |
59 |
$ |
49 |
$ |
187 |
$ |
146 |
||||||||
|
Other (income) expense |
$ |
2 |
$ |
(4 |
) |
$ |
(25 |
) |
$ |
(2 |
) |
|||||
|
Income tax expense |
$ |
203 |
$ |
115 |
$ |
601 |
$ |
254 |
||||||||
|
Net income available to common stockholders before |
||||||||||||||||
|
cumulative effect of change in accounting principle |
$ |
274 |
$ |
189 |
$ |
946 |
$ |
516 |
||||||||
|
Cumulative effect of change in accounting principle |
-- |
-- |
47 |
-- |
||||||||||||
|
Net income available to common stockholders |
$ |
274 |
$ |
189 |
$ |
993 |
$ |
516 |
||||||||
|
Earnings per share - before cumulative effect |
||||||||||||||||
|
of change in accounting principle - basic |
$ |
1.09 |
$ |
0.76 |
$ |
3.79 |
$ |
2.08 |
||||||||
|
Earnings per share - before cumulative effect |
||||||||||||||||
|
of change in accounting principle - diluted |
$ |
1.09 |
$ |
0.74 |
$ |
3.74 |
$ |
2.01 |
||||||||
|
Cumulative effect of change in accounting principle |
||||||||||||||||
|
per share - basic |
$ |
-- |
$ |
-- |
$ |
0.19 |
$ |
-- |
||||||||
|
Cumulative effect of change in accounting principle |
||||||||||||||||
|
per share - diluted |
$ |
-- |
$ |
-- |
$ |
0.18 |
$ |
-- |
||||||||
|
Earnings per share - basic |
$ |
1.09 |
$ |
0.76 |
$ |
3.98 |
$ |
2.08 |
||||||||
|
Earnings per share - diluted |
$ |
1.09 |
$ |
0.74 |
$ |
3.92 |
$ |
2.01 |
||||||||
Net Income
In the third quarter of 2003, Anadarko reported net income available to common stockholders of $274 million, or $1.09 per share (diluted) compared to net income available to common stockholders of $189 million, or $0.74 per share (diluted) for the third quarter of 2002. For the nine-month period ended September 30, 2003, Anadarko's net income available to common stockholders was $993 million, or $3.92 per share (diluted). For the nine months ended September 30, 2003, net income available to common stockholders before the cumulative effect of change in accounting principle was $946 million, or $3.74 per share (diluted). By comparison, for the nine months ended September 30, 2002, Anadarko's net income available to common stockholders was $516 million, or $2.01 per share (diluted).
In 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," which 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. The change was effective January 2003 and the related cumulative adjustment to net income was an increase of $47 million after taxes, or $0.18 per share (diluted). The application of SFAS No. 143 did not have a material impact on the Company's depreciation, depletion and amortization (DD&A) rate. There was no impact on the Company's cash flow as a result of adopting SFAS No. 143.
Unrealized gains and losses on derivative instruments that do not meet the conditions to qualify for hedge accounting are recognized in gas sales and oil sales and are reflected in the average sales prices. In the third quarter of 2003, these amounts for prior periods were reclassified from other (income) expense to gas sales and oil sales. The amount of the reclassification was not significant and had no effect on net income or per share amounts.
Revenues
Three Months Ended
Nine Months Ended
September 30
September 30
millions
2003
2002
2003
2002
Gas sales
$
762
$
425
$
2,165
$
1,290
Oil and condensate sales
458
422
1,337
1,197
Natural gas liquids sales
85
57
255
156
Other sales
35
34
87
87
Total
$
1,340
$
938
$
3,844
$
2,730
Total revenues for the third quarter 2003 increased $402 million or 43% compared to the third quarter of 2002 due primarily to significant increases in commodity prices and a slight increase in sales volumes. For the nine months ended September 30, 2003, total revenues increased $1.1 billion or 41% compared to the nine months ended September 30, 2002 due primarily to significant increases in commodity prices, partially offset by a slight decrease in sales volumes.
The impact of hedges and marketing activities resulted in a net decrease in realized prices of $0.03 per thousand cubic feet (Mcf) of gas and $0.99 per barrel of oil for the third quarter of 2003 compared to market prices, decreasing revenues $21 million. For the third quarter of 2002, the impact of hedges and marketing activities resulted in a net increase (decrease) in realized prices of $0.20 per Mcf of gas and $(1.10) per barrel of oil compared to market prices, increasing revenues $12 million. For the nine months ended September 30, 2003, the impact of hedges and marketing activities resulted in a net decrease in realized prices of $0.39 per Mcf of gas and $1.36 per barrel of oil compared to market prices, decreasing revenues $257 million. For nine months ended September 30, 2002, the impact of hedges and marketing activities resulted in a net increase (decrease) in realized prices of $0.13 per Mcf of gas and $(0.30) per barrel of oil compared to market prices, increasing revenues $50 million.
During the third quarter of 2003, Anadarko sold 50 MMBOE, an increase of 2 MMBOE or 4% compared to sales of 48 MMBOE in the third quarter of 2002. The increase in volumes was due primarily to higher gas production in East Texas and Louisiana. For the nine months ended September 30, 2003, Anadarko sold 142 MMBOE, a decrease of 6 MMBOE or 4% compared to sales of 148 MMBOE for the same period of 2002. The decrease in volumes was due primarily to the 2002 divestiture of heavy oil properties in Canada and slightly lower sales volumes in Algeria and other international areas.
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 3 of this Form 10-Q.
Natural Gas Sales Volumes and Average Prices
Three Months Ended
Nine Months Ended
September 30
September 30
2003
2002
2003
2002
United States (Bcf)
136
126
378
389
MMcf/d
1,481
1,375
1,383
1,423
Price per Mcf
$
4.48
$
2.64
$
4.41
$
2.63
Canada (Bcf)
33
36
103
99
MMcf/d
357
389
379
364
Price per Mcf
$
4.65
$
2.53
$
4.83
$
2.69
Total (Bcf)
169
162
481
488
MMcf/d
1,838
1,764
1,762
1,787
Price per Mcf
$
4.51
$
2.62
$
4.50
$
2.64
Bcf - billion cubic feet
Mcf - thousand cubic feet
MMcf/d - million cubic feet per day
The Company's natural gas sales volumes for the third quarter 2003 were up 7 Bcf or 4% compared to the third quarter of 2002. The increase in volumes was due primarily to higher gas production in East Texas and Louisiana, partially offset by a decrease in volumes in Canada primarily due to temporary operational issues. For the first nine months of 2003, natural gas sales volumes were down 7 Bcf or 1% compared to the same period of 2002. The decreases in volumes are due primarily to a decrease in the Company's sales volumes within the United States, primarily in the Gulf of Mexico and the Mid-Continent, as a result of operational issues and natural production declines. This decrease is partially offset by increases in natural gas sales volumes in East Texas and Louisiana and Canada due to successful exploration and development activities. Production of natural gas is generally not directly affected by seasonal swings in demand.
The Company's average realized natural gas price for the three and nine months ended September 30, 2003 increased 72% and 70%, respectively, from the same periods of 2002. Strong demand in North American consumption due to colder weather and declining gas supply resulted in significantly higher North American gas prices. These higher prices were partially offset by commodity price hedges on 52% and 48% of natural gas sales volumes during the three and nine months ended September 30, 2003, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of September 30, 2003, the Company has hedged about 54% and 30% of its anticipated natural gas wellhead sales volumes for the remainder of 2003 and 2004, respectively. See Derivative Instruments under Item 3 of this Form 10-Q.
Crude Oil and Condensate Sales Volumes and Average Prices
Three Months Ended
Nine Months Ended
September 30
September 30
2003
2002
2003
2002
United States (MMBbls)
8
8
26
23
MBbls/d
97
84
96
88
Price per barrel
$
26.34
$
24.77
$
26.45
$
22.28
Canada (MMBbls)
2
3
5
10
MBbls/d
17
37
17
37
Price per barrel
$
26.43
$
19.36
$
27.56
$
18.57
Algeria (MMBbls)
5
5
14
16
MBbls/d
51
51
52
57
Price per barrel
$
27.66
$
26.91
$
28.06
$
23.54
Other International (MMBbls)
2
2
5
6
MBbls/d
24
19
19
21
Price per barrel
$
23.68
$
22.05
$
22.94
$
19.34
Total (MMBbls)
17
18
50
55
MBbls/d
189
191
184
203
Price per barrel
$
26.36
$
24.02
$
26.64
$
21.64
MMBbls - million barrels
MBbls/d - thousand barrels per day
Anadarko's crude oil and condensate sales volumes for the third quarter of 2003 decreased 1 MMBbls or 6% compared to the third quarter of 2002, due to volumes in Canada. Crude oil and condensate sales volumes for the nine months ended September 30, 2003 decreased 5 MMBbls or 9% compared to the nine months ended September 30, 2002. The decrease in crude oil and condensate volumes was due to a decrease of 5 MMBbls in Canada, 2 MMBbls in Algeria and 1 MMBbls in other international areas related primarily to Venezuela, partially offset by an increase of 3 MMBbls in the United States.
The decrease in Canada volumes is due largely to the sale of the Company's heavy oil assets in late 2002. The decrease in Algeria volumes is due primarily to the substantial completion of cost recovery, whereby Anadarko was reimbursed for previous exploration spending with additional barrels of oil production. The decrease in Venezuela volumes is due primarily to the contract terms with the national oil company of Venezuela under which Anadarko earns a fee that is translated into barrels of oil based on current prices that results in lower oil volumes when prices increase. The increase in the United States is primarily in the Western division. Production of oil is not usually affected by seasonal swings in demand.
Anadarko's average realized crude oil prices for the three and nine months ended September 30, 2003 increased 10% and 23%, respectively, compared to the same periods of 2002. The increase in crude oil prices during 2003 is attributed primarily to political unrest in the Middle East, the oil workers' strike in Venezuela, low oil inventory levels and increased demand. These higher prices were partially offset by commodity price hedges on 37% and 38% of crude oil and condensate sales volumes during the three and nine months ended September 30, 2003, respectively, that reduced the Company's exposure to low prices and limited participation in higher prices. As of September 30, 2003, the Company has hedged about 38% and 15% of its anticipated oil and condensate sales volumes for the remainder of 2003 and 2004, respectively. See Derivative Instruments under Item 3 of this Form 10-Q.
The Company's natural gas liquids (NGLs) sales volumes for the three months ended September 30, 2003 were essentially flat compared to the same period of 2002. For the nine months ended September 30, 2003, NGLs sales volumes increased 1 MMBbls or 9% compared to the same period of 2002. During the three and nine months ended September 30, 2003, average NGLs prices increased 32% and 52%, respectively, compared to the same periods of 2002. The increase in NGLs prices is attributed to a comparable rise in natural gas prices coupled with historically lower levels of NGLs inventories in the United States. NGLs production is dependent on natural gas prices and the economics of processing the natural gas volumes to extract NGLs.
Costs and Expenses
Three Months Ended
Nine Months Ended
September 30
September 30
millions
2003
2002
2003
2002
Operating expenses
$
207
$
172
$
587
$
555
Administrative and general
75
78
249
227
Depreciation, depletion and amortization
341
288
954
829
Other taxes
70
50
216
168
Impairments related to oil and gas properties
74
--
92
33
Restructuring costs
33
--
33
--
Total
$
800
$
588
$
2,131
$
1,812
During the third quarter of 2003, Anadarko's costs and expenses increased $212 million or 36% compared to the third quarter of 2002 due to the following factors:
|
-- |
Operating expenses increased $35 million (20%) primarily due to higher costs associated with oil and gas producing activities and processing NGLs. |
|
-- |
Administrative and general expenses decreased $3 million (4%) primarily due to lower salaries expenses associated with the reduction in the Company's workforce. |
|
-- |
DD&A expense increased $53 million (18%) primarily due to higher DD&A rates. |
|
-- |
Other taxes increased $20 million (40%) primarily due to higher production taxes related to significantly higher commodity prices received in 2003. |
|
-- |
Impairments of oil and gas properties are due to a $68 million ceiling test impairment for Qatar as a result of lower future production estimates and unsuccessful exploration activities and a $6 million impairment due to unsuccessful exploration activities in Gabon, Tunisia and Angola. |
|
-- |
Restructuring costs of $33 million related to one-time charges for employee termination benefits and other costs associated with the Company's cost reduction plan. See Outlook on Liquidity . |
For the nine-month period ended September 30, 2003, costs and expenses increased $319 million or 18% compared to the same period of 2002 due to the following factors:
|
-- |
Operating expenses increased $32 million (6%) primarily due to higher costs associated with oil and gas producing activities, partially offset by lower costs for processing NGLs. |
|
-- |
Administrative and general expenses increased $22 million (10%) primarily due to higher salaries and benefits expenses associated with the Company's workforce during the first six months of 2003. |
|
-- |
DD&A expense increased $125 million (15%) primarily due to higher DD&A rates. |
|
-- |
Other taxes increased $48 million (29%) primarily due to higher production taxes related to significantly higher commodity prices received in 2003. |
|
-- |
Impairments of oil and gas properties in 2003 are due to a $68 million ceiling test impairment for Qatar as a result of lower future production estimates and unsuccessful exploration activities and $24 million due primarily to unsuccessful exploration activities in Australia, Gabon, Tunisia and Angola. Impairments of $33 million in 2002 related primarily to activities in Congo, Oman and Australia. |
|
-- |
Restructuring costs of $33 million related to one-time charges for employee termination benefits and other costs associated with the Company's cost reduction plan. |
Interest Expense
Three Months Ended
Nine Months Ended
September 30
September 30
millions
2003
2002
2003
2002
Gross interest expense
$
89
$
91
$
281
$
267
Capitalized interest
(30
)
(42
)
(94
)
(121
)
Net interest expense
$
59
$
49
$
187
$
146
Gross interest expense for the three and nine months ended September 30, 2003 decreased 2% and increased 5%, respectively, compared to the same periods of 2002. The increase for the nine months ended September 30, 2003 was due primarily to the expensing of debt issuance costs related to the Company redeeming the Zero Coupon Convertible Debentures due 2020 in 2003 and slightly higher interest rates caused by the redemption of the Zero Yield Puttable Contingent Debt Securities in 2002, which were replaced with higher rate debt. See Capital Resources and Liquidity and Outlook on Liquidity .
For the three and nine months ended September 30, 2003, capitalized interest decreased by 29% and 22%, respectively, compared to the same periods of 2002. The decreases are primarily due to a decrease in capitalized costs that qualify for interest capitalization.
Other (Income) Expense
Three Months Ended
Nine Months Ended
September 30
September 30
millions
2003
2002
2003
2002
Firm transportation keep-whole contract valuation
$
8
$
(19
)
$
(10
)
$
(28
)
Ineffectiveness of derivative financial instruments
(6
)
2
(3
)
10
Foreign currency exchange
(1
)
13
(15
)
4
Gas sales contracts - accretion of discount
1
3
5
7
Other
--
(3
)
(2
)
5
Total
$
2
$
(4
)
$
(25
)
$
(2
)
Other expense in the third quarter of 2003 increased $6 million compared to the same period of 2002. The increase was due primarily to a $27
million increase related primarily to the effect of lower market values for firm transportation subject to a keep-whole agreement and a $3 million increase in other losses, partially offset by a $14 million increase in Canadian currency exchange gains, an $8 million increase in gains for ineffectiveness of derivative financial instruments and a $2 million decrease in accretion of discount.
For the nine months ended September 30, 2003, other income increased $23
million compared to the same period of 2002 due primarily to a $19 million increase in Canadian currency exchange gains, a $13 million increase in gains for ineffectiveness of derivative financial instruments, a $7 million increase in other gains and a $2 million decrease in accretion of discount, partially offset by an $18 million decrease in other income related primarily to the effect of lower market values for firm transportation subject to a keep-whole agreement. See Derivative Instruments and Foreign Currency Risk under Item 3 of this Form 10-Q.
|
Income Tax Expense |
||||||||||||||||
|
Three Months Ended |
Nine Months Ended |
|||||||||||||||
|
|
|
September 30 |
|
|
September 30 |
|
||||||||||
|
|
|
|
|
|
|
|
||||||||||
|
millions |
2003 |
2002 |
2003 |
2002 |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Income tax expense |
$ |
203 |
$ |
115 |
$ |
601 |
$ |
254 |
||||||||
For the third quarter of 2003, income taxes increased $88 million or 77% compared to the third quarter of 2002. For the first nine months of 2003, income taxes increased $347 million or 137% compared to the same period of 2002. The increase in income taxes is due primarily to higher earnings before income taxes.
The effective tax rate for the third quarter of 2003 and 2002 was 42% and 38%, respectively. The effective tax rate for the first nine months of 2003 and 2002 was 39% and 33%, respectively. The variances in the effective tax rate for the three and nine months ended September 30, 2003 and 2002 from the statutory rate of 35% were due primarily to income taxes related to foreign operations.
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. 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 purchases some physical volumes for resale primarily from partners and producers near Anadarko's production. These purchases allow the Company to aggregate larger volumes and attract larger, creditworthy customers, which in turn enhance 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. The Company also conducts trading activities for the purpose of generating profits on or from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs.
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 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 3 of this Form 10-Q.
During 2002, all segments of the energy 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 2003, Anadarko has not experienced any material financial losses associated with credit deterioration of third-party purchasers; however, in certain situations the Company has declined to transact with some counter-parties and changed its sales terms to require some counter-parties to pay in advance or post letters of credit for purchases.
Marketing Contracts The following tables 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 September 30, 2003. The Company records income or loss on these activities using the mark-to-market method.
Firm
Marketing
Transportation
millions
and Trading
Keep-whole
Total
Fair value of contracts outstanding as of
$
(5
)
$
(73
)
$
(78
)
Contracts realized or otherwise settled during 2003
(2
)
(19
)
(21
)
Fair value of new contracts when entered into during 2003
2
--
2
Other changes in fair value
16
10
26
Fair value of contracts outstanding as of
$
11
$
(82
)
$
(71
)
December 31, 2002 - assets (liabilities)
|
|
|
Fair Value of Contracts as of September 30, 2003 |
|
||||||||||||||||
|
|
|
|
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Assets (Liabilities)
|
Maturity Less than
|
Maturity
|
Maturity
|
Maturity
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Marketing and Trading |
|||||||||||||||||||
|
Prices actively quoted |
$ |
6 |
$ |
4 |
$ |
1 |
$ |
-- |
$ |
11 |
|||||||||
|
Prices based on models and other valuation |
|||||||||||||||||||
|
methods |
-- |
-- |
-- |
-- |
-- |
||||||||||||||
|
Firm Transportation Keep-whole |
|||||||||||||||||||
|
Prices actively quoted |
$ |
(29 |
) |
$ |
-- |
$ |
-- |
$ |
-- |
$ |
(29 |
) |
|||||||
|
Prices based on models and other valuation |
|||||||||||||||||||
|
methods |
-- |
(34 |
) |
(18 |
) |
(1 |
) |
(53 |
) |
||||||||||
|
Total |
|||||||||||||||||||
|
Prices actively quoted |
$ |
(23 |
) |
$ |
4 |
$ |
1 |
$ |
-- |
$ |
(18 |
) |
|||||||
|
Prices based on models and other valuation |
|||||||||||||||||||
|
methods |
-- |
(34 |
) |
(18 |
) |
(1 |
) |
(53 |
) |
||||||||||
Exploration and Development Activities
During the third quarter of 2003, Anadarko participated in a total of 289 wells, including 180 gas wells, 99 oil wells and 10 dry holes. This compares to a total of 211 wells, including 167 gas wells, 35 oil wells and 9 dry holes during the third quarter of 2002.
For the first nine months of 2003, Anadarko participated in a total of 866 wells, including 562 gas wells, 261 oil wells and 43 dry holes. This compares to a total of 733 wells, including 534 gas wells, 165 oil wells and 34 dry holes during the first nine months of 2002. Following are highlights of third quarter 2003 activity:
|
-- |
Anadarko and its partners made their third and fourth exploration successes in the past 12 months in Algeria's Berkine Basin. The most recent discovery, the BKNE-AAC-A well, is located in Block 404 and was drilled to a depth of 11,200 feet and encountered 36 net feet of oil pay.
|
|
-- |
In Wyoming, construction is progressing on a 125-mile pipeline to transport carbon dioxide recovered from the Shute Creek gas processing plant in southwest Wyoming to Anadarko's enhanced oil recovery (EOR) project at the Salt Creek field north of Casper. The pipeline construction is expected to be complete by January 2004. Anadarko's successful pilot program has generated encouraging results and confirms the expected EOR performance to increase oil production over the next several years from 5 MBbls/d to a peak rate of 35 MBbls/d. |
|
|
|
|
Capital Expenditures* |
||||||||||
|
Nine Months Ended |
||||||||||
|
|
|
September 30 |
|
|||||||
|
|
|
|
|
|||||||
|
millions |
2003 |
2002 |
||||||||
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
||||
|
Development |
$ |
1,169 |
$ |
825 |
||||||
|
Exploration |
396 |
497 |
||||||||
|
Acquisitions of oil and gas properties |
312 |
201 |
||||||||
|
Gathering and general |
52 |
38 |
||||||||
|
Capitalized interest and internal costs related to exploration |
||||||||||
|
and development activities |
236 |
269 |
||||||||
|
|
|
|
|
|
|
|
|
|||
|
Total |
$ |
2,165 |
$ |
1,830 |
||||||
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
* Excludes corporate acquisitions. |
||||||||||
During the first nine months of 2003, Anadarko's capital spending was $2.2 billion, an increase of $335 million or 18% compared to the same period of 2002. This increase is primarily due to a $344 million increase in development spending and a $111 million increase in acquisitions of oil and gas properties, partially offset by a $101 million decrease in exploration spending and a $19 million decrease in other spending.
Debt As of September 30, 2003, Anadarko's total debt was $5.45 billion. This compares to total debt of $5.47 billion at December 31, 2002.
In April 2003, Anadarko redeemed for cash its callable Zero Coupon Convertible Debentures due 2020. Anadarko funded the $384 million redemption with available credit facilities that carry a lower effective interest rate. Anadarko paid $556.46 per debenture, reflecting the issue price plus accrued interest at 3.5%.
In May 2003, the Company issued $350 million principal amount of 3.25% Notes due 2008. The net proceeds from this issuance were used to reduce floating interest rate debt that was incurred in April 2003 to redeem the Zero Coupon Convertible Debentures due 2020.
In October 2003, the Company terminated its existing revolving credit agreements and entered into a $750 million 364-Day Revolving Credit Agreement with a syndicate of U.S. and Canadian lenders. The agreement terminates in October 2004 or October 2005, if any loan under the agreement is converted to a term loan.
Anadarko's net cash from operating activities during the nine months ended September 30, 2003 was $2.3 billion compared to $1.5 billion for the same period in 2002. The increase in cash flow is attributed primarily to a significant increase in commodity prices. The Company's capital expenditure budget for 2003 is $2.8 billion. The increase of $0.5 billion from the original budget is expected to enable Anadarko to accelerate its exploration program in the Gulf of Mexico, Algeria and Canada, more aggressively develop key producing fields in Canada and East Texas, and includes the acquisition of oil and gas properties in the Gulf of Mexico.
In July 2003, Anadarko announced a cost reduction plan that is expected to eliminate more than $100 million of overhead costs from the Company's annual cost structure, which includes cuts in personnel and corporate expenses. This cost reduction plan is expected to reduce costs and expenses by $60 million and capitalized overhead by $40 million. Restructuring costs associated with this plan are expected to be approximately $36 million and will be charged to income as specific liabilities are incurred. Restructuring costs of $33 million were expensed in the third quarter of 2003. These relate to one-time termination benefits ($28 million), contract termination costs ($3 million) and other costs ($2 million). The majority of the remaining restructuring costs are expected to be paid and expensed in the fourth quarter of 2003.
In conjunction with the cost reduction plan, the Company is in the process of evaluating the allocation of capital resources to international exploration for 2004. While Management sees an important place for international projects within its portfolio, Anadarko may narrow the list of international projects in order to focus its efforts. Depending on what choices are made, it is likely that the Company may record impairments not expected to exceed $45 million in the fourth quarter of 2003 for international exploration projects that the Company elects not to pursue or for possible divestitures of other non-core assets. Additionally, any price weakness in Qatar at year-end 2003 as compared to the end of the third quarter could result in additional non-cash impairments for that project in the fourth quarter.
Cash flow from operating activities in 2003 is expected to be about $3.1 billion. The Company plans to repay about $300 million in debt for the year. Cash flow from operating activities will vary depending upon, among other things, actual commodity prices received throughout the remainder of 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 below where oil and gas were trading in the third 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. No stock repurchases have been budgeted for 2003 or are currently anticipated.
Both exchange and over-the-counter traded derivative instruments are subject to margin deposit requirements. Margin deposits are required of the Company whenever its unrealized losses with a counter-party exceed predetermined 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 counter-parties in order to satisfy these margin deposit requirements. During the first nine months of 2003, the Company's margin deposit requirements ranged from zero to $125 million. The Company's margin deposit requirement was $18 million on September 30, 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 Securities and Exchange Commission. 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, the exercise of stock options or the Company's Employee Savings Plan and Employee Stock Ownership Plan equity funded contributions.Common Stock Dividend
In October 2003, the Board of Directors of Anadarko declared a quarterly dividend on the Company's common stock of 14 cents per share. This represents a 40% increase over the dividend paid in each of the previous four quarters. The amount of future dividends for Anadarko common stock will depend on earnings, financial condition, capital requirements and other factors. The Board of Directors will determine dividends on a quarterly basis.
The Company's credit agreements allow for a maximum capitalization ratio of 60% debt exclusive of the effect of any non-cash writedowns. As of September 30, 2003, Anadarko's capitalization ratio was 40% 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 September 30, 2003.
New Accounting Principles and Recent Developments
For information on New Accounting Principles see Note 1 - Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Derivative Instruments Held for Non-Trading Purposes The Company had equity production hedges of 288 billion cubic feet of natural gas and 19 million barrels of crude oil as of September 30, 2003. As of September 30, 2003, the Company had a net unrealized loss of $179 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 $142 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 September 30, 2003, the Company had a net unrealized loss of $6 million (gains of $33 million and losses of $39 million) on commodity derivative instruments entered into for trading purposes and a net unrealized gain of $17 million (gains of $32 million and losses of $15 million) on physical contracts entered into for trading purposes. Based upon an analysis utilizing the actual derivative contractual volumes and assuming a 10% increase in underlying commodity prices, the potential additional loss on the derivative instruments and physical delivery contracts would be approximately $4 million.
Firm Transportation Keep-Whole Agreement A company Anadarko acquired in 2000 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 pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko 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 September 30, 2003, accounts payable included $29 million and other long-term liabilities included $53 million related to this agreement. As of December 31, 2002, accounts payable included $5 million and other long-term liabilities included $68 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 $8 million. The future gain or loss from this agreement cannot be accurately predicted. For additional information related to the keep-whole agreement, see
Note 7 - Financial Instruments of the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.
For additional information regarding the Company's marketing and trading portfolio and the firm transportation keep-whole agreement see
Marketing Strategies under Item 2 of this Form 10-Q.
Commodity Risk 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. In addition, in OPEC countries in which Anadarko has production such as Algeria, Venezuela and Qatar, when the world oil market is weak, the Company may be subject to periods of decreased production due to government mandated cutbacks. 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 depreciation, depletion and amortization will be reduced.
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 September 30, 2003 and December 31, 2002, a Canadian subsidiary had $99 million and $98 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 September 30, 2003 Canadian exchange rate would be about $9 million based on the outstanding debt at September 30, 2003.
At September 30, 2003 and December 31, 2002, the Company's Latin American subsidiaries had foreign deferred tax liabilities denominated in the local currency equivalent totaling $36 million and $49 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 $21 million. The potential foreign currency remeasurement impact on net earnings from a 10% increase in the September 30, 2003 Latin American exchange rates would be approximately $3 million.
Anadarko's Chief Executive Officer and Chief Financial Officer (Certifying Officers) performed an evaluation of the Company's disclosure controls and procedures. 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 Securities 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 as of September 30, 2003. In addition, there has been no significant change in the Company's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect the Company's internal control over financial reporting.
PART II. OTHER INFORMATION
See
Note 15 -- Contingencies of the Notes to Consolidated Financial Statements under Part I - Item 1 of this Form10-Q.
|
(a) |
Exhibits |
|
Exhibits not incorporated by reference to a prior filing are designated by an (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. |
Exhibit
Original Filed
File
Number
Description
Exhibit
Number
3
(a)
Restated Certificate of Incorporation
4(a) to Form S-3 dated
333-60496
of Anadarko Petroleum Corporation,
May 9, 2001
dated August 28, 1986
(b)
By-laws of Anadarko Petroleum
3(e) to Form 10-Q
1-8968
Corporation, as amended
for the quarter ended
September 30, 2000
(c)
Certificate of Amendment of Anadarko's
4.1 to Form 8-K dated
1-8968
Restated Certificate of Incorporation
July 28, 2000
4
(a)
Certificate of Designation of 5.46%
4(a) to Form 8-K dated
1-8968
Cumulative Preferred Stock, Series B
May 6, 1998
(b)
Rights Agreement, dated as of October 29,
4.1 to Form 8-A dated
1-8968
1998, between Anadarko Petroleum
October 30, 1998
Corporation and The Chase Manhattan Bank
10
(b)(i)
Termination Agreement and Release of All Claims
10(b)(i) to Form 10-Q
1-8968
for the quarter ended
June 30, 2003
(ii)
Form of Amendment to Anadarko Petroleum
10(b)(ii) to Form 10-Q
1-8968
Corporation Key Employee Change of Control
for the quarter ended
Contract
June 30, 2003
(iii)
Form of Anadarko Petroleum Corporation 1998
10(b)(iii) to Form 10-Q
1-8968
Director Stock Plan Stock Option Agreement
for the quarter ended
June 30, 2003
*(iv)
Anadarko Petroleum Corporation
Officer Severance Plan
*(v)
Form of Termination Agreement and
Release of All Claims Under Officer Severance Plan
*12
Computation of Ratios of Earnings to Fixed
Charges and Earnings to Combined Fixed
Charges and Preferred Stock Dividends
*31
Rule 13a--14(a)/15d--14(a) Certifications
*32
Section 1350 Certifications
(b)
Reports on Form 8-K
A report on Form 8-K dated July 31, 2003 was furnished. The event was reported under Item 9 - Regulation FD Disclosure and Item 12 - Results of Operations and Financial Condition.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned duly authorized officer and principal financial officer.
|
ANADARKO PETROLEUM CORPORATION |
||||
|
(Registrant) |
||||
|
November 12, 2003 |
By: |
/s/ MICHAEL E. ROSE |
||
|
|
|
|
||
|
Michael E. Rose - Executive Vice President |
||||
|
|
and Chief Financial Officer |
|||
EXHIBIT 10(b)(iv)
ANADARKO PETROLEUM CORPORATION
OFFICER SEVERANCE PLAN
WHEREAS , Anadarko Petroleum Corporation desires to provide a program of severance benefits for certain of its employees;
NOW, THEREFORE , the Anadarko Petroleum Corporation Officer Severance Plan (the "Plan") shall be and is hereby adopted, effective as of July 15, 2003:
I.
DEFINITIONS AND CONSTRUCTION
1.1 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.
(a) "Base Pay" shall mean the annual rate of base compensation paid by the Company to a Covered Employee (including amounts which the Covered Employee could have received in cash had he not elected to contribute to an employee benefit plan maintained by the Company), excluding overtime pay, bonuses, employee benefits, added premiums, differentials, components of foreign service assignments, and all forms of incentive compensation. The annual rate of base compensation is determined by multiplying the Covered Employee's monthly rate of pay times twelve (12).
(b) "Company" shall mean Anadarko Petroleum Corporation and any successor thereto, not including any subsidiaries and affiliates.
(c) "Covered Employee" shall mean any individual who is an officer of the Company and who is designated by the Company as an executive officer as being covered by the Plan. An executive officer will include any individual with one or more of the following titles: Chief Executive Officer, President, Executive Vice-President, Senior Vice-President or Vice-President. At the sole discretion of the Company an individual who has been designated as covered by the Plan may at any time be removed from Plan coverage on a prospective basis and will be notified by the Company in writing of such removal from the Plan. An individual shall automatically cease to be a Covered Employee if and when he ceases to be an executive officer as designated by the Company.
(d) "Date of Hire" shall mean the most recent date the Covered Employee was hired by the Company.
(e) "Involuntary Termination" shall mean any termination of a Covered Employee's employment with the Company which does not result from a resignation or retirement by the Covered Employee; provided, however, the term "Involuntary Termination" shall not include:
(1) a Termination for Cause;
(2) a termination as a result of the Covered Employee's death;
(3) any termination as the result of the Covered Employee's disability under circumstances entitling him to benefits under the Company's short-term or long-term disability plans;
(4) any termination which the Company expects to be of short duration and pursuant to which the Covered Employee is subject to reemployment with the Company within a reasonable period of time (as determined by the Plan Administrator);
(5) any termination of a Covered Employee's employment with the Company by reason of continued failure of the Covered Employee to perform the Covered Employee's duties or responsibilities with the Company (other than any such failure resulting from incapacity due to physical or mental illness or injury);
(6) any termination resulting from or in connection with any corporate sale transaction (including, without limitation, a sale of any assets of the Company, a sale of any assets of any affiliate or subsidiary of the Company, a sale of the stock of a subsidiary or affiliate of the Company) where continued employment is available to a Covered Employee without an extended break in employment; or
(7) a termination if the Covered Employee is eligible to receive benefits from the Anadarko Petroleum Corporation Change of Control Severance Pay Plan or a Key Employee Change of Control Contract as a result of or in connection with such termination.
(f) "Pay In Lieu of Notice" shall mean payment as determined by the Company in its sole discretion made to a Covered Employee whose employment is terminated by the Company without advance notice.
(g) "Plan Administrator" shall mean the Company or a committee or individual appointed by the Company as Plan Administrator.
(h) "Severance Amount" shall mean such term as described in Section 2.1(a).
(i) "Termination for Cause" shall mean any termination of a Covered Employee's employment with the Company by reason of the Covered Employee's (1) conviction of any felony or of a misdemeanor involving moral turpitude, (2) willful failure to perform his duties or responsibilities, (3) engagement in conduct which is injurious (monetarily or otherwise) to the Company or any of its affiliates (including, without limitation, misuse of the Company's or an affiliate's funds or other property), (4) engagement in business activities which are in conflict with the business interests of the Company, (5) insubordination, (6) engagement in conduct which is in violation of the Company's safety rules or standards or which otherwise causes or may cause injury to another employee or any other person, (7) engagement in conduct which is in violation of any policy or work rule of the Company or (8) engagement in conduct which is in violation of the Company's Code of Business Conduct and Ethics or which is otherwise inappropriate in the office or work environment.
1.2 Number and Gender . Wherever appropriate herein, word 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.
1.3 Headings . The headings of Articles and Sections herein are included solely for convenience and if there is any conflict between such headings and the text of the Plan, the text shall control.
II.
SEVERANCE BENEFITS
2.1 Severance Benefits . The severance benefits provided under the Plan are as follows:
(a) If a Covered Employee who is subject to an Involuntary Termination agrees to execute and does, in fact, execute a release as described in Section 2.2, he shall be entitled to a minimum Severance Amount of Base Pay. The foregoing notwithstanding on a case by case basis with respect to any individual Covered Employee or group of Covered Employees the Company may, in its sole discretion, increase the Severance Amount; and provided, further, that the Company, in its sole discretion, may with respect to any Covered Employee and on a case by case basis waive any condition or rule imposed under the Plan as a condition for eligibility for a Severance Amount benefit. If a Covered Employee who is subject to an Involuntary Termination does not execute a release as described in Section 2.2, he shall be entitled to Pay in Lieu of Notice, if any, as determined under Section 2.1(b).
(b) The Company may, in its sole discretion and where it deems appropriate, pay an amount of Pay in Lieu of Notice to a Covered Employee when such Covered Employee has been terminated by the Company without advance notice if he is not otherwise eligible for benefits under this Plan or to any other employee whose employment has been terminated by the Company without advance notice.
(c) Any Covered Employee who becomes eligible to receive a payment described in Paragraph (a) or (b) above shall be entitled to continue his and his family members' coverage under the Company's medical and dental benefit plans for a period of time and in a manner as the Company may determine in its sole discretion; provided that such coverage may be continued only at the level and for the person or persons covered as in effect as of the date of the Covered Employee's Involuntary Termination. The Company may, in its sole discretion and where it deems appropriate, provide for other perquisites or benefits in a manner the Company may determine in its sole discretion.
The Plan Administrator shall have the sole discretion to determine if a Covered Employee's employment by the Company has been subject to an Involuntary Termination. Any determination by the Plan Administrator regarding the nature of a Covered Employee's termination of his employment with the Company shall be final and binding. Payments provided herein shall be subject to any required tax withholding.
2.2 Termination Agreement and Release of all Claims . As a condition to receipt of any Severance Amount benefit hereunder, a Covered Employee whose employment by the Company has been subject to an Involuntary Termination will be required to execute a release agreement in the form established by the Company, releasing the Company, its shareholders, partners, officers, directors, employees and agents from any and all claims and from any and all causes of action of any kind or character, including but not limited to all claims or causes of action arising out of such Covered Employee's employment with the Company or the termination of such employment. Irrespective of a Covered Employee's execution of the required release agreement, the performance of the Company's obligations hereunder and the Covered Employee's receipt and acceptance of benefits provided hereunder by such Covered Employee shall constitute full settlement of all such claims and causes of action. If severance payments have been paid pursuant to the Plan to a Covered Employee whose employment by the Company was subject to an Involuntary Termination and such Covered Employee thereafter fails to comply in full with the terms of such release agreement, the release agreement shall remain valid and may be enforced by the Company, and such Covered Employee may be obligated to refund to the Company an amount equal to the excess of his Severance Amount over any payments received under Section 2.1(b) and the Company shall have the right to offset against any further monies or benefits owed to such Covered Employee (to the extent such offset is permissible under applicable law) the Severance Amount excess such Covered Employee is obligated to return to the Company.
2.3 Mitigation . A Covered Employee shall not be required to seek other employment or to otherwise engage in any mitigation effort to receive the benefit of any payment provided for in this Article II, nor shall the amount of any payment provided for in this Article II be reduced by any compensation or benefit earned by the Covered Employee as the result of employment by another employer or by retirement benefits.
2.4 Severance Offset . Any Severance Amount paid under this Plan will be reduced dollar-for-dollar by any severance pay, statutory benefits or pay in lieu of notice paid by the Company to a Covered Employee under applicable law or under any other plan or programs of the Company (including, without limitation, any arrangement providing for the payment of severance benefits to employees arising in connection with any acquisition, merger or other business combination to which the Company is a party and for which such Covered Employee is eligible).
III.
ADMINISTRATION OF PLAN
3.1 Plan Administration . For the purposes of the Plan and the Employee Retirement Income Security Act of 1974, as amended, the "plan administrator" and named fiduciary of the Plan is the Plan Administrator. The Plan Administrator shall establish such rules and procedures as may be necessary to enable it to discharge its duties hereunder. The Plan 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 authorize the payment of benefits under the Plan;
(d) To prepare and distribute information explaining the Plan;
(e) To appoint or employ persons to assist in the administration of the Plan; and
(f) To obtain such information as is necessary for the proper administration of the Plan.
The Plan Administrator may allocate to others certain aspects of the management, operation and responsibilities of the Plan, including the employment of advisors and the delegation of any ministerial duties or functions to qualified individuals.
3.2 Claims Procedure . Claims for Plan benefits and reviews of appeals of Plan benefit claims which have been denied or modified are to be processed in accordance with the written Plan claims procedures established by the Plan Administrator and adopted by the Company, which procedures are hereby incorporated by reference as a part of the Plan.
IV.
GENERAL PROVISIONS
4.1 Funding . The benefits provided herein shall be unfunded and shall be provided from the Company's general assets.
4.2 Cost of Plan . The entire cost of the Plan shall be borne by the Company and no contributions shall be required of the Covered Employees.
4.3 Plan Year . The Plan shall operate on a plan year consisting of the twelve consecutive month period commencing on January 1 of each year.
4.4 Amendment and Termination . The Plan may be amended from time to time, or terminated and discontinued, at any time, in each case at the discretion of the Company. A Plan amendment shall be effected by execution by the Company of a written instrument of Plan amendment. Plan termination shall be effected by adoption by the Company of a resolution to terminate the Plan and by execution by the Company of a written instrument of Plan termination.
4.5 Not Contract of Employment . The adoption and maintenance of the Plan shall not be deemed to be a contract of employment between the Company and any person or to be consideration for the employment of any person. Nothing herein contained shall be deemed to give any person the right to be retained in the employ of the Company or to restrict the right of the Company to discharge any person at any time nor shall the Plan be deemed to give the Company the right to require any person to remain in the employ of the Company or to restrict any person's right to terminate his employment at any time.
4.6 Severability . Any provision in the Plan that is prohibited or unenforceable in any jurisdiction by reason of applicable law shall, as to such jurisdiction, be ineffective only to the extent of such prohibition or unenforceability without invalidating or affecting the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
4.7 Nonalienation . Covered Employees shall not have any right to pledge, hypothecate, anticipate or assign benefits or rights under the Plan, except by will or the laws of descent and distribution.
4.8 Governing Law . THE PLAN SHALL BE INTERPRETED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS EXCEPT TO THE EXTENT PREEMPTED BY FEDERAL LAW.
IN WITNESS WHEREOF , the Company has executed this Plan this 28 th day of July, 2003.
ANADARKO PETROLEUM CORPORATION
By:
Richard A. Lewis
Vice President, Human Resources
EXHIBIT 10(b)(v)
TERMINATION AGREEMENT
AND RELEASE OF ALL CLAIMS
In consideration of the severance benefits set forth in Section 2.1 of the Anadarko Petroleum Corporation Officer Severance Plan, this Termination Agreement and Release of All Claims ("Agreement"), is made and entered into by {EMPLOYEE} (hereinafter referred to as "Employee") and Anadarko Petroleum Corporation (hereinafter referred to as "Anadarko" or the "Company").
By signing this Agreement, the Employee and Company agree as follows:
1. Purpose. The purpose of this Agreement is to provide for the orderly termination of the employment relationship between the parties, and to voluntarily resolve any actual or potential disputes or claims that the Employee has or might have, as of the date of the Employee's execution of this Agreement, against the Company and the Company's owners, parents, subsidiaries, affiliates, directors, officers, employees, agents, attorneys, representatives, and assigns (hereinafter collectively referred to as the "Released Parties"). Neither the fact that this Agreement has been proposed or executed, nor the terms of this Agreement, are intended to suggest, or should be construed as suggesting, that the Released Parties have acted unlawfully or violated any federal, state or local law or regulation, or any other duty, policy or contract.
2. Resignation/Termination. Effective {DATE OF TERMINATION}, the Employee's employment shall terminate. Employee shall continue to perform such duties as determined by the Company and shall assist in the transition of the Employee's duties until such date.
3. Termination Benefits . In consideration for the Employee's execution of, and required performance under, this Agreement, the Company shall provide the Employee with the following Termination Benefits, which benefits the Employee would not otherwise have received, or been entitled to receive (the Compensation & Benefits Committee in its sole discretion may approve and determine any or all of the following italicized items) :
a) Payment of Employee's current monthly base salary through his termination date; and
b) Payment of earned, but unused vacation in accordance with the Company policy; and
c) Severance payment equal to (a minimum of 12 months base salary) , less applicable taxes; and
d) Continuation of existing medical and dental plan coverage at current active employee rates for a minimum of six months; and
e) (Payment of COBRA continuation coverage under the Company's medical and dental plans for a specified period of time) ; and
f) Company shall continue to provide the Employee with tax preparation and financial planning services, for (a minimum of six months) , from a vendor selected by the Company; and
g) (Any other noncash benefits or perquisites as applicable to the Employee's position) .
4. Waiver of Additional Compensation or Benefits . The Termination Benefits to be paid to the Employee under Section 3 above constitute the entire amount of compensation and consideration due to the Employee under this Agreement, and the Employee acknowledges that he or she has no right to seek, and will not seek, any additional or different compensation or consideration for executing or performing under this Agreement. Furthermore, in addition to any other waiver or releases under this Agreement, the Employee expressly waives all rights, and releases the Released Parties from all obligations, under: (a) any other severance plan or program offered by or on behalf of the Company; and (b) the Employee's Key Employee Change of Control Contract (the "COC Contract"). Employee expressly acknowledges, agrees, and represents, with the intention that it be relied upon by the Company, that his or her waiver and release with respect to the COC Contract is meant to be effective notwithstanding the provisions of Section 1(b) of the COC Contract; and that Section 1(b) of the COC Contract shall be null and void and of no further force and effect.
5. Neutral Employment Reference. The Company shall provide a neutral employment reference to any potential employers that consider the employment of the Employee and that seek information concerning the reasons for the departure of the Employee. The Company will provide to any such potential employers the identity of the positions held by the Employee and the dates of the Employee's employment with the Company.
6. Tax Consequences. The Company has made no representations to the Employee regarding the tax consequences of any Termination Benefit received by the Employee under this Agreement.
7. Non-Disclosure Obligations. The Employee shall never, without first obtaining the express written consent of the Company, or being compelled to do so by a court of competent jurisdiction: (a) disclose the existence or terms of this Agreement, nor the substance of the negotiations leading to this Agreement, to any other person or entity; save and except to his immediate family, personal counsel or attorney, personal accountants, personal tax preparer, personal and attending doctors and mental health care professionals, and/or the appropriate taxing authorities (who will then be deemed governed by the non-disclosure agreement herein); (b) use, or disclose to any third party, any of the Company's confidential business, or other proprietary information; (c) make any remarks disparaging the business reputation of the Company. The Employee expressly acknowledges that his or her breach of these obligations will likely cause irreparable and substantial harm to the Company, and, thus, that the obligations may be enforced by injunctive relief. The Employee further expressly acknowledges that any breach of the non-disparagement obligation set forth in subsection (c) above will cause damages that are difficult to quantify, and, thus, that any breach of that obligation may, and should, be remedied by an award of liquidated damages in the amount of $60,000.
8. Employee Representations. The Employee expressly acknowledges and represents, and intends for the Company to rely upon his or her representations that he or she:
(1) Has not filed any complaints, claims or actions against the Company with any court, agency, or commission regarding the matters encompassed by this Agreement and that he will not do so at any time in the future, and that if any court or agency assumes jurisdiction of any complaint, claim or action against the Company on behalf of Employee, he will direct that court or agency to withdraw from or dismiss with prejudice the matter.
(2) Understands that he or she is, by entering into this Agreement, releasing the Released Parties, including the Company, from any and all claims he or she may have against them under federal, state, or local law, which have arisen on or before the date of execution of this Agreement.
(3) Understands that he or she is, by entering into this Agreement, waiving all claims that he or she may have against the Released Parties under the federal Age Discrimination in Employment Act of 1967, as amended, which have arisen on or before the date of execution of this Agreement.
(4) Has reviewed all aspects of this Agreement, and has carefully read and fully understands all of the provisions and effects of this Agreement.
(5) Has been, and is hereby, advised in writing to consult with an attorney before signing this Agreement.
(6) Is knowingly and voluntarily entering into this Agreement, and has relied solely and completely upon his or her own judgment and, if applicable, the advice of his attorney in entering into this Agreement.
(7) Is not relying upon any representations, promises, predictions, projections, or statements made by or on behalf of any Released Party, other than those that are specifically stated in this written Agreement.
(8) Does not waive rights or claims that may arise after the date this Agreement is signed.
(9) will receive payment of consideration beyond that which the Employee was entitled to receive before entering into this Agreement.
9. Release. The Employee, on behalf of himself or herself, and his or her heirs, executors, administrators, successors and assigns, hereby fully and forever releases, acquits and discharges the Released Parties, jointly and severally, from all claims, demands, actions, lawsuits, grievances, and obligations of any nature whatsoever that do or might, or that might be assigned, as of the date that this Agreement is executed by the Employee. The Employee acknowledges, understands and represents that this release specifically includes, but is not limited to, all claims: (a) arising under any federal, state, and local employment laws, regulations, executive orders, and ordinances, including, but not limited to, Title VII of the Civil Rights Act of 1964, as amended; the Civil Rights Act of 1991; the Age Discrimination in Employment Act of 1967, as amended; the Americans With Disabilities Act of 1990; the Employee Retirement Income Security Act of 1974 ("ERISA"), as amended; the Family and Medical Leave Act; the Texas Commission on Human Rights Act, as amended; the Texas Labor Code; and any local human rights law; (b) arising under or concerning any alleged contract or agreement; (c) for any alleged tort; and (d) under any equitable or other theory or recovery.
10. Twenty-One Days to Consider Offer of Termination Benefits. The Employee shall have, and by signing this Agreement the Employee acknowledges and represents that he or she has had, the opportunity to take up to twenty-one (21) days to consider whether to elect to sign this Agreement, and to thereby waive and release the rights and claims addressed in this Agreement. Although the Employee may sign this Agreement prior to the end of the 21-day period, the Employee shall be deemed, by doing so, to have certified and agreed that the decision to make such election prior to the expiration of the 21-day period of time is knowing and voluntary and was not induced by the Company through: (a) fraud, misrepresentation, or a threat to withdraw or alter the offer prior to the end of the 21-day period; or (b) an offer to provide different terms or benefits in exchange for signing the release prior to the expiration of the 21-day period.
11. Seven Day Revocation Period. The Employee may revoke this Agreement at any time within seven (7) days after he or she signs it. To revoke the Agreement, the Employee must deliver written notification of such revocation to the attention of _______________ within seven (7) days after the date the Employee signs this Agreement. Employee further understands that if he does not revoke the Agreement within seven (7) days following its execution (excluding the date of execution), it will become effective, binding, and enforceable.
12. Entire Agreement. This Agreement sets forth the entire agreement of the Employee and fully supercedes and replaces any and all prior agreements or understandings, written or oral, between the Company and the Employee pertaining to the subject matter of this Agreement.
13. Miscellaneous. Should any provision of this Agreement be declared or be determined by any court of competent jurisdiction to be illegal, invalid or unenforceable, all remaining provisions of this Agreement shall otherwise remain in full force and effect and be construed as if such illegal, invalid, or unenforceable provision has not been included herein.
It is further understood and agreed that if a violation of any term of this Agreement is asserted, the party who asserts such violation will have the right to seek specific performance of that term and/or any other necessary and proper relief as permitted by law, including but not limited to, damages from any court of competent jurisdiction, and the prevailing party shall be entitled to recover its reasonable costs and attorney's fees.
Nothing in this Agreement will be construed to prevent the Employee from challenging the validity of this Agreement under the Age Discrimination in Employment Act or Older Workers' Benefit Protection Act. The Employee further understands and agrees that if he or someone acting on his behalf files, or causes to be filed, any such claim, charge, complaint, or action against the Company and/or other entities, he expressly waives any right to recover any damages or other relief, whatsoever from the Company and/or other entities including costs and attorneys' fees.
Notwithstanding anything to the contrary, this Agreement does not replace or reduce any rights Employee has to vested and accrued benefits under the Anadarko Employee Savings Plan, Anadarko Retirement Plan, Anadarko Savings Restoration Plan and/or Anadarko Retirement Restoration Plan.
14. Choice of Law. This Agreement shall be governed by, and construed and interpreted in accordance with, the laws of the state of Texas without regard to principles of conflict of laws.
ANADARKO PETROLEUM CORPORATION
By: _____________________________
Dated this ___ day of _________________, 200__
EMPLOYEE
By: ______________________________
Dated this ___ day of _________________, 200__
_____ Employee's initials
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
Nine Months Ended September 30, 2003 and Five Years Ended December 31, 2002
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Nine Months |
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Ended |
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September 30, |
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Years Ended December 31 |
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millions except ratio amounts |
2003 |
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2002 |
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2001 |
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2000 |
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1999 |
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1998 |
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Gross Income (Loss) |
$ |
1,738 |
$ |
1,410 |
$ |
(298 |
) |
$ |
1,519 |
$ |
179 |
$ |
(7 |
) |
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Rentals |
7 |
14 |
14 |
16 |
11 |
12 |
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Earnings (Loss) |
1,745 |
1,424 |
(284 |
) |
1,535 |
190 |
5 |
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Gross Interest Expense |
281 |
358 |
301 |
193 |
96 |
82 |
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Rentals |
7 |
14 |
14 |
16 |
11 |
13 |
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Fixed Charges |
$ |
288 |
$ |
372 |
$ |
315 |
$ |
209 |
$ |
107 |
$ |
95 |
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Preferred Stock |
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Dividends |
6 |
9 |
11 |
17 |
17 |
11 |
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Combined Fixed Charges |
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and Preferred Stock |
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Dividends |
$ |
294 |
$ |
381 |
$ |
326 |
$ |
226 |
$ |
124 |
$ |
106 |
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Ratio of Earnings to |
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Fixed Charges |
6.06 |
3.83 |
n/m |
7.35 |
1.77 |
0.05 |
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Ratio of Earnings to |
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Combined Fixed Charges |
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and Preferred Stock |
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Dividends |
5.94 |
3.74 |
n/m |
6.80 |
1.53 |
0.05 |
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n/m - not meaningful |
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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 31
CERTIFICATIONS
I, Robert J. Allison, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;
2. Based on my knowledge, this 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 report;
3. Based on my knowledge, the financial statements, and other financial information included in this 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 report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: November 12, 2003
/s/ ROBERT J. ALLISON, JR.
Chairman, President and Chief Executive Officer
CERTIFICATIONS
I, Michael E. Rose, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;
2. Based on my knowledge, this 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 report;
3. Based on my knowledge, the financial statements, and other financial information included in this 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 report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: November 12, 2003
/s/ MICHAEL E. ROSE
Executive Vice President and Chief Financial Officer
EXHIBIT 32
SECTION 1350 CERTIFICATION OF PERIODIC REPORT
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, Robert J. Allison, Jr., Chairman, President and Chief Executive Officer of Anadarko Petroleum Corporation (Company) and Michael E. Rose, Executive Vice President and Chief Financial Officer of the Company, certify that:
(1) the Quarterly Report on Form 10-Q of the Company for the period ending September 30, 2003, as filed with the Securities and Exchange Commission on the date hereof (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.
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November 12, 2003 |
/s/ ROBERT J. ALLISON, JR. |
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Robert J. Allison, Jr. |
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Chairman, President and Chief Executive Officer |
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November 12, 2003 |
/s/ MICHAEL E. ROSE |
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Michael E. Rose |
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Executive Vice President and Chief |
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Financial Officer |
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This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.