UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
--------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
-------------- -------------------
Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 ROSECRANS AVENUE, SUITE 4000, EL SEGUNDO, CALIFORNIA 90245
(Address of principal executive offices) (Zip Code)
(310) 726-7600
(Registrant's Telephone Number, Including Area Code)
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
(as defined in Rule 12b-2 of the Act). Yes X No
------- -------
Number of shares of Common Stock, $1 par value, outstanding as of
April 30, 2004: 263,550,447
TABLE OF CONTENTS
PAGE
Glossary.................................................................... i
PART I FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Earnings............................................. 1
Consolidated Balance Sheets....................................... 2
Consolidated Cash Flows........................................... 3
Notes to Consolidated Financial Statements........................ 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations....................... 27
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 38
Item 4. Controls and Procedures............................................. 42
PART II OTHER INFORMATION
Item 1. Legal Proceedings................................................... 43
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases
of Equity Securities................................................ 43
Item 6. Exhibits and Reports on Form 8-K.................................... 44
SIGNATURE................................................................... 44
EXHIBIT INDEX............................................................... 45
GLOSSARY
Below are definitions of certain key terms that may be in use in this Form 10-Q:
M Thousand Bbl Barrels
MM Million Cf/d Cubic feet per day
B Billion Cfe/d Cubic feet of gas
T Trillion equivalent per day
Btu British thermal units
CF Cubic feet DD&A Depreciation, depletion
and amortization
BOE Barrels of oil equivalent NGLs Natural gas liquids
Liquids Crude oil, condensate
and NGLs
Bbl/d Barrels per day
o API Gravity is a measurement of the gravity (density) of crude oil and
other liquid hydrocarbons by a system recommended by the American Petroleum
Institute ("API"). The measuring scale is calibrated in terms of "API
degrees." The higher the API gravity, the lighter the oil.
o Bilateral institution refers to a country specific institution, which lends
funds primarily to promote the export of goods from that country. Examples
of bilateral institutions are Ex-Im (U.S.), Hermes (Germany), SACE (Italy),
COFACE (France), and JBIC (Japan).
o BOE is a term used to quantify oil and natural gas amounts using a standard
measurement. Gas volumes are converted to barrels of oil equivalent on the
basis of energy content, where the volume of natural gas that when burned
produces the same amount of heat as a barrel of oil (6,000 cubic feet of
gas equals one barrel of oil equivalent).
o British Thermal Units ("Btu") is a standardized unit of measure for energy,
equivalent to the amount of heat required to raise the temperature of one
pound of water one degree Fahrenheit. Ten thousand MMBtu (million Btu) is
the standard volume for exchange traded natural gas derivative contracts,
the approximate heat content of ten thousand Mcf (thousand cubic feet) of
natural gas.
o Delineation or appraisal well is a well drilled in an unproven area
adjacent to a discovery well to define the boundaries of the reservoir.
o Development well is a well drilled within the proved area of an oil or
natural gas reservoir to a depth of a stratigraphic horizon known to be
productive.
o Dry hole is a well incapable of producing hydrocarbons in sufficient
commercial quantities to justify future capital expenditures for completion
and additional infrastructure.
o Economic interest method pursuant to production sharing contracts is a
method by which the Company's share of the cost recovery revenue and the
profit revenue is divided by market oil and gas prices and represents the
volume to which the Company is entitled. The lower the commodity price, the
higher the volume entitlement, and vice versa.
o Exploratory well is a well drilled to find and produce oil or natural gas
reserves that is not a development well.
o Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof
to another party who agrees to pay a portion of past or future costs. The
interest received by an assignee is a "farm-in," while the interest
transferred by the assignor is a "farm-out."
o Field is an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature or stratigraphic condition.
o Floating Production Storage and Offloading ("FPSO") technology refers to
the use of a vessel that is stationed above or near an offshore oil field.
Produced fluids from subsea completion wells are brought by flowlines to
the vessel where they are separated, treated, stored and then offloaded to
another vessel for transportation.
i
o Gross acres or gross wells are the total acres or wells in which the
Company has a working interest.
o Hydrocarbons are organic compounds of hydrogen and carbon atoms that form
the basis of all petroleum products.
o Lifting is the amount of liquids each working-interest partner takes
physically. The liftings may actually be more or less than actual
entitlements based on royalties, working interest percentages, and a number
of other factors.
o Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been
liquefied in a refrigeration and pressurization process to facilitate
storage and transportation.
o Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other
light hydrocarbons. At normal temperature it is a gas, but when cooled or
subjected to pressure it can be stored and transported as a liquid.
o Multilateral institution refers to an institution with shareholders from
multiple countries that lends money for specific development reasons.
Examples of multilateral institutions are International Finance Corporation
("IFC"), European Bank for Reconstruction and Development ("EBRD"), and
Asian Development Bank ("ADB").
o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and
natural gasolines which can be extracted from wet natural gas and become
liquid under various combinations of increasing pressure and lower
temperature.
o Net acreage and net oil and gas wells are obtained by multiplying gross
acreage and gross oil and gas wells by the Company's working interest
percentage in the properties.
o Net pay is the amount of oil or gas saturated rock capable of producing oil
or gas.
o OPEC is the abbreviation for Organization of Petroleum Exporting Countries.
o Production Sharing Contract ("PSC") is a contractual agreement between the
Company and a host government whereby the Company, acting as contractor,
bears all exploration, development and production costs in return for an
agreed upon share of the proceeds from the sale of production.
o Producible well is a well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
production exceed production expenses and taxes.
o Prospective acreage is lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas.
o Proved acreage is acreage that is allocated to producing wells or wells
capable of production or to acreage that is being developed.
o Reservoir is a porous and permeable underground formation containing oil
and/or natural gas enclosed or surrounded by layers of less permeable rock
and is individual and separate from other reservoirs.
o Subsea tieback is a well with the wellhead equipment located on the bottom
of the ocean.
o Take-or-Pay is a type of contract clause where specific quantities of a
product must be paid for, even if delivery is not taken. Normally, the
purchaser has the right in following years to take product that had been
paid for but not taken.
o Trend or Play is an area or region of concentrated activity with a group of
related fields and prospects.
o Working interest is the percentage of ownership the Company has in a joint
venture, partnership, consortium, project or acreage. Net working interest
is working interest after deducting royalties.
o West Texas Intermediate ("WTI") crude oil is a light, sweet crude oil (high
API gravity, low sulfur) used as the benchmark for U.S. crude oil refining
and trading. WTI is deliverable at Cushing, Oklahoma to fill New York
Mercantile Exchange ("NYMEX") futures contracts for light, sweet crude oil.
ii
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months
Ended March 31,
----------------------------
Millions of dollars except per share amounts 2004 2003
- --------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ 1,837 $ 1,775
Interest, dividends and miscellaneous income 11 11
Gain on sales of assets 44 3
- --------------------------------------------------------------------------------
Total revenues 1,892 1,789
Costs and other deductions
Crude oil, natural gas and product purchases 750 646
Operating expense 288 294
Administrative and general expense 63 51
Depreciation, depletion and amortization 232 260
Impairments 5 -
Dry hole costs 25 71
Exploration expense 50 55
Interest expense 41 38
Property and other operating taxes 20 22
Distributions on convertible preferred
securities of subsidiary trust - 8
- --------------------------------------------------------------------------------
Total costs and other deductions 1,474 1,445
Earnings from equity investments 37 43
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Earnings from continuing operations before
income taxes and minority interests 455 387
- --------------------------------------------------------------------------------
Income taxes 181 168
Minority interests 5 2
- --------------------------------------------------------------------------------
Earnings from continuing operations 269 217
Cumulative effect of accounting changes (a) - (83)
- --------------------------------------------------------------------------------
Net earnings $ 269 $ 134
================================================================================
Basic earnings per share of common stock (b)
Continuing operations $ 1.03 $ 0.84
Cumulative effect of accounting changes - (0.32)
- --------------------------------------------------------------------------------
Net earnings $ 1.03 $ 0.52
================================================================================
Diluted earnings per share of common stock (c)
Continuing operations $ 1.00 $ 0.82
Cumulative effect of accounting changes - (0.30)
- --------------------------------------------------------------------------------
Net earnings $ 1.00 $ 0.52
================================================================================
Cash dividends declared per share of common stock $ 0.20 $ 0.20
- --------------------------------------------------------------------------------
(a) Net of tax (benefit) $ - $ (48)
(b) Basic weighted average shares
outstanding (in thousands) 261,974 258,005
(c) Diluted weighted average shares
outstanding (in thousands) 276,889 271,729
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEETS UNOCAL CORPORATION
At March 31, At December 31,
---------------------------------
Millions of dollars 2004 (a) 2003
- --------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 760 $ 404
Accounts and notes receivable - net 1,227 1,292
Inventories 110 141
Deferred income taxes 116 119
Other current assets 38 35
- --------------------------------------------------------------------------------
Total current assets 2,251 1,991
Investments and long-term receivables - net 871 892
Properties - net (b) 8,399 8,324
Goodwill 131 131
Deferred income taxes 302 300
Other assets 182 160
- --------------------------------------------------------------------------------
Total assets $12,136 $11,798
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,101 $ 1,072
Taxes payable 432 326
Dividends payable 52 52
Interest payable 51 43
Current portion of environmental liabilities 116 118
Current portion of long-term debt 62 248
Other current liabilities 232 226
- --------------------------------------------------------------------------------
Total current liabilities 2,046 2,085
Long-term debt 3,199 2,635
Deferred income taxes 721 704
Accrued abandonment, restoration
and environmental liabilities 860 844
Other deferred credits and liabilities 1,013 960
Minority interests 47 39
Commitments and contingencies - Note 15
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely
parent debentures - 522
Common stock ($1 par value,
shares authorized: 750,000,000 (c)) 273 271
Capital in excess of par value 1,105 1,031
Unearned portion of restricted stock issued (31) (13)
Retained earnings 3,672 3,456
Accumulated other comprehensive income (331) (298)
Notes receivable - key employees (7) (27)
Treasury stock - at cost (d) (431) (411)
- --------------------------------------------------------------------------------
Total stockholders' equity 4,250 4,009
- --------------------------------------------------------------------------------
Total liabilities and stockholders' equity $12,136 $11,798
================================================================================
(a) Unaudited
(b) Net of accumulated depreciation,
depletion and amortization of: $11,953 $11,711
(c) Number of shares outstanding (in thousands) 262,372 260,594
(d) Number of shares (in thousands) 11,162 10,623
The Company follows the successful efforts method of accounting for its oil and
gas activities.
See Notes to the Consolidated Financial Statements.
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Three Months
Ended March 31,
---------------------------------
Millions of dollars 2004 2003
- --------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 269 $ 134
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 232 260
Impairments 5 -
Dry hole costs 25 71
Amortization of exploratory leasehold costs 16 24
Deferred income taxes 28 30
Gain on sales of assets (44) (3)
Pension expense net of contributions 23 20
Restructuring provisions net of payments (7) -
Cumulative effect of accounting changes - 83
Other (6) 12
Working capital and other changes related to operations
Accounts and notes receivable 72 (122)
Inventories 31 6
Accounts payable 29 86
Taxes payable 106 123
Other (29) (39)
- --------------------------------------------------------------------------------
Net cash provided by operating activities 750 685
- --------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (360) (429)
Proceeds from sales of assets 72 66
Return of capital from affiliate company 52 -
- --------------------------------------------------------------------------------
Net cash used in investing activities (236) (363)
- --------------------------------------------------------------------------------
Cash Flows from Financing Activities
Long-term borrowings 40 16
Reduction of long-term debt and capital lease obligations (197) (100)
Minority interests - (2)
Repurchases of common stock (20) -
Proceeds from issuance of common stock 51 1
Dividends paid on common stock (52) (52)
Loans to key employees 20 3
- --------------------------------------------------------------------------------
Net cash used in financing activities (158) (134)
- --------------------------------------------------------------------------------
Net increase in cash and cash equivalents 356 188
- --------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 404 168
- --------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 760 $ 356
================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 33 $ 35
Income taxes (net of refunds) $ 6 $ 23
See Notes to the Consolidated Financial Statements.
-3-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. General
The consolidated financial statements included in this report are unaudited and,
in the opinion of management, include all adjustments necessary for a fair
presentation of financial position and results of operations. All adjustments
are of a normal recurring nature. Such financial statements are presented in
accordance with the Securities and Exchange Commission's ("SEC") disclosure
requirements for Form 10-Q.
These interim consolidated financial statements should be read in conjunction
with the consolidated financial statements and the related notes filed with the
SEC in Unocal Corporation's 2003 Annual Report on Form 10-K, as amended.
For the purpose of this report, Unocal Corporation ("Unocal") and its
consolidated subsidiaries, including Union Oil Company of California ("Union
Oil"), are referred to as the "Company."
The consolidated financial statements of the Company include the accounts of
subsidiaries in which a controlling interest is held and variable interest
entities where the Company is the primary beneficiary. Investments in entities
without a controlling interest are accounted for by the equity method. Under the
equity method, the investments are stated at cost plus the Company's equity in
undistributed earnings and losses after acquisition. Income taxes estimated to
be payable when earnings are distributed are included in deferred income taxes.
Results for the three months ended March 31, 2004, are not necessarily
indicative of future financial results.
The Company has made changes in the reporting of its segments from the reporting
utilized in the 2003 Annual Report on Form 10-K, as amended. The financial
statements of the prior periods have been reclassified to conform to the 2004
presentation.
2. Accounting Changes
SFAS No. 132 (revised 2003): In 2003, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 132, "Employers" Disclosures about Pensions
and Other Postretirement Benefits (revised 2003)." In accordance with this
pronouncement, beginning in 2004, quarterly reports include disclosure of the
components of net pension and postretirement benefit cost as well as the changes
in the estimated current year contributions to the plans. In addition, benefit
payment information will be included in the Company's 2004 Annual Report on Form
10-K.
FASB Interpretation No. 46 (revised December 2003): Effective January 1, 2004
the Company adopted Financial Accounting Standards Board ("FASB") Interpretation
No. 46 (revised December 2003), "Consolidation of Variable Interest Entities
("VIE") which clarifies the definition of a VIE and provides a scope exception
for certain entities that meet the Statement's definition of a "business." This
pronouncement resulted in the deconsolidation of Unocal Capital Trust (the
"Trust") (see note 13 for further details). As a result, the $522 million
obligation for the Trust's convertible preferred securities was removed from the
consolidated balance sheet and replaced by an increase in long-term debt for the
$538 million in 6-1/4% convertible junior subordinated debentures of Unocal
payable to the Trust. The Company also recorded its $16 million investment in
the Trust on the consolidated balance sheet. The deconsolidation did not affect
consolidated net earnings.
Other Matters: The Company has classified the cost of acquiring oil and gas
drilling rights in property, plant and equipment. The FASB's Emerging Issues
Task Force ("EITF") has on their agenda Issue No. 03-S, "Application of FASB
Statement No. 142, Goodwill and Other Intangible Assets, to oil and gas
companies." This issue addresses whether oil and gas drilling rights are
intangible assets, and whether those assets are subject to the classification
and disclosure provisions of SFAS No. 142. The resolution of this issue will
have no impact on the Company's results of operations and statement of cash
flows. If the EITF determines that the cost of oil and gas drilling rights
should be classified as intangible assets, it would result in additional
disclosures and a balance sheet reclassification of these assets from
"Properties-net" to "Intangible Assets"
-4-
amounting to approximately $1.48 billion and $1.53 billion at March 31, 2004
and December 31, 2003, respectively. In a similar issue, in March 2004, the
EITF determined that the mineral rights of mining companies are tangible assets.
Subsequent to this EITF consensus, the FASB has amended both SFAS No. 141,
"Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets," to clarify that mineral rights are tangible assets.
However, Issue 03-S remains to be addressed by the EITF.
In December 2003, "The Medicare Prescription Drug, Improvement and Modernization
Act of 2003" (the "Act") was enacted, which introduces a prescription drug
benefit under Medicare Part D. The availability of the new drug benefit could
cause Medicare eligible plan participants to leave their current
employer-sponsored plans (or cause employees to join such plans), depending on
the drug benefits provided under those plans relative to the benefits provided
by Medicare. The Act also provides that a non-taxable federal subsidy will be
paid to sponsors of postretirement benefit plans that provide retirees with a
drug benefit that is at least "actuarially equivalent" to the Medicare Part D
benefit. In accordance with FASB Staff Position 106-1, the Company has deferred
the accounting for this Act and thus any measures of the accumulated
postretirement benefit obligation or net periodic postretirement benefit cost in
the consolidated financial statements or accompanying notes do not reflect the
effects of the Act on the plan. Specific authoritative guidance on the
accounting for the federal subsidy is pending and that guidance, when issued,
could require the sponsors to change previously reported information. The
Company is studying the Act to determine its economic impact. The federal
subsidy is not payable to a plan sponsor for retirees who leave their current
employer-sponsored plan to participate in the Medicare drug program. Final
detailed regulations specifying the manner in which actuarial equivalency must
be determined and the evidence required to demonstrate it are not yet available.
It is not known whether the Company will amend the plan in response to the new
legislation.
EITF Issue 03-1, "The Meaning of Other-Than-Temporary Impairment and Its
Application to Certain Investments," is effective with the 2004 Form 10-K and
requires additional disclosures for cost method investments. Effective with the
third quarter of 2004, this also requires recognition and measurement guidance
regarding impairment of cost method investments. The Company has not determined
the impact of these new directives.
EITF issue 03-16, "Accounting for Investments in Limited Liability Companies
("LLCs")," is effective beginning with the third quarter 2004. This
pronouncement will cause some entities to be accounted for on the equity rather
than the cost basis. The Company is studying this rule.
3. Other Financial Information
o During the first quarters of 2004 and 2003, approximately 28 percent
and 25 percent, respectively, of total sales and operating revenues
were attributable to the resale of liquids and natural gas purchased
from others in connection with marketing activities. Related purchase
costs are classified as expense in the crude oil, natural gas and
product purchases category on the consolidated earnings statement.
o Capitalized interest totaled $16 million in both the first quarters
of 2004 and 2003.
o Exploration expense on the consolidated earnings statement consisted
of the following:
For the Three Months
Ended March 31,
---------------------------
Millions of dollars 2004 2003
- --------------------------------------------------------------------------------
Exploration operations $ 17 $ 15
Geological and geophysical 15 14
Amortization of exploratory leasehold costs 16 24
Leasehold rentals 2 2
- --------------------------------------------------------------------------------
Exploration expense $ 50 $ 55
================================================================================
-5-
o The Company repurchased 539,208 shares from four of the original
participants of its Executive Stock Purchase Program of 2000 at market
prices in the first quarter of 2004. The purchases, which aggregated
to approximately $20 million, were accounted for as Treasury Stock on
the consolidated balance sheet. The recipients used the proceeds to
repay the loans made by the Company for the original acquisition of
the shares.
4. Dispositions Of Assets
The Company's subsidiary, Unocal North Sumatra Geothermal, Ltd. ("UNSG"),
received about $60 million from PT PLN (Persero) ("PLN"), the state electricity
utility, for the sale of the Company's rights and interests in the Sarulla
geothermal project on the island of Sumatra, Indonesia. PLN acquired UNSG's
interest in the Joint Operation Contract with Pertamina, the Indonesian national
petroleum company, and the Energy Sales Contract with PLN. The Company recorded
a $21 million after-tax gain from the sale in the first quarter of 2004.
5. Restructuring
In 2003, the Company accrued $38 million pre-tax in restructuring charges and
adopted a plan for streamlining the organizational structures in order to align
them with the Company's portfolio requirements and business needs. These charges
were included in administrative and general expense on the consolidated earnings
statement in the second, third and fourth quarters of 2003. At March 31, 2004,
335 of 360 employees had been terminated or had been advised of planned
termination dates as a result of the plan. The following table reflects the 2004
payments activity. The majority of the remaining liability of $19 million is
expected to be paid by the end of 2004.
Training
Millions of dollars (except employees) Termination Out-placement
Costs Costs
- ------------------------------------------------------------------------------
Liability at December 31, 2003 $ 24 $ 2
- ------------------------------------------------------------------------------
1st Quarter Payments 7 -
- ------------------------------------------------------------------------------
Liability at March 31, 2004 $ 17 $ 2
==============================================================================
6. Income Taxes
Income taxes on earnings from continuing operations for the first quarter of
2004 were $181 million compared with $168 million for the first quarter of 2003.
The effective income tax rate for the first quarter of 2004 was 40 percent
compared with 43 percent for the first quarter of 2003. The overall lower
effective tax rate is due primarily to lower average taxes on foreign earnings
in the first quarter of 2004, as compared to 2003.
-6-
7. Earnings Per Share
The following are reconciliations of the numerators and denominators of the
basic and diluted earnings per share ("EPS") computations for earnings from
continuing operations for the first quarters ended March 31, 2004 and 2003:
- --------------------------------------------------------------------------------
Earnings Shares Per Share
Millions except per share amounts (Numerator)(Denominator) Amount
- --------------------------------------------------------------------------------
Three months ended March 31, 2004
Earnings from continuing operations $ 269 262.0
Basic EPS $ 1.03
========
Effect of dilutive securities
Options and common stock equivalents 2.7
----------------------
269 264.7 $ 1.02
Interest on convertible debentures
payable to trust (after-tax) 7 12.3
----------------------
Diluted EPS $ 276 277.0 $ 1.00
========
- --------------------------------------------------------------------------------
Three months ended March 31, 2003
Earnings from continuing operations $ 217 258.0
Basic EPS $ 0.84
========
Effect of dilutive securities
Options and common stock equivalents 1.5
----------------------
217 259.5 $ 0.84
Distributions on subsidiary trust
preferred securities (after-tax) 7 12.3
----------------------
Diluted EPS $ 224 271.8 $ 0.82
========
- --------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the three months ended March
31, 2004 and 2003, were options outstanding to purchase approximately 1.4
million and 11 million shares, respectively, of common stock. These options were
not included in the computation as the exercise prices were greater than average
market prices of the common shares during the respective quarters.
8. Stock-Based Compensation
Prior to 2003, the Company applied Accounting Principles Board ("APB") Opinion
No. 25, "Accounting for Stock Issued to Employees," and related interpretations
in accounting for stock-based compensation. Accordingly, stock-based
compensation expense recognized in the Company's consolidated earnings included
expenses related to the Company's various cash incentive plans that are paid to
certain employees based upon defined measures of the Company's common stock
price performance and total shareholder return. In addition, the amounts also
included expenses related to the Company's Pure Resources, Inc. ("Pure")
subsidiary, which had its own stock-based compensation plans. Under APB Opinion
No. 25, stock-based employee compensation cost was not recognized in earnings
when stock options granted had an exercise price equal to the market value of
the underlying common stock on the date of grant.
Effective January 1, 2003, the Company adopted the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation,"
prospectively to all employee awards granted, modified, or settled after
December 31, 2002. Therefore, the cost related to stock-based employee
compensation included in the determination of net earnings for 2004 is less than
that which would have been recognized if the fair value based method had been
applied to all awards since the original effective date of SFAS No. 123. The
following table illustrates the effect on net earnings and earnings per share if
the fair value based method had been applied to all outstanding and unvested
awards in each period:
-7-
For the Three Months
Ended March 31,
------------------------
Millions of dollars except per share amounts 2004 2003
- --------------------------------------------------------------------------------
Net earnings
As reported $ 269 $ 134
Add: Stock-based employee compensation expense
included in reported net income, net of
related tax effects and minority interests 5 2
Deduct: Total stock-based employee compensation
expense determined under the fair value based
method for all awards, net of related tax
effects and minority interests (7) (4)
------------------------
Pro forma net earnings $ 267 $ 132
========================
Net earnings per share:
Basic - as reported $ 1.03 $ 0.52
Basic - pro forma $ 1.02 $ 0.51
Diluted - as reported $ 1.00 $ 0.52
Diluted - pro forma $ 0.99 $ 0.51
9. Comprehensive Income
The Company's comprehensive income was:
For the Three Months
Ended March 31,
------------------------
Millions of dollars 2004 2003
- --------------------------------------------------------------------------------
Net earnings $ 269 $ 134
Change in unrealized gain (loss)
on hedging instruments (a) (27) (10)
Reclassification adjustment for
settled hedging contracts (b) 3 7
Unrealized foreign currency translation adjustments (9) 46
- --------------------------------------------------------------------------------
Total comprehensive income $ 236 $ 177
================================================================================
(a) Net of tax effect of: (16) (6)
(b) Net of tax effect of: 2 4
-8-
10. Assets Held for Sale
In the first quarter of 2004, the Company's UNSG subsidiary sold its rights and
interests in the Sarulla geothermal project on the island of Sumatra, Indonesia
(see note 4 - Disposition of Assets). This property was held for sale as of
December 31, 2003.
At March 31, 2004, the Company was in the process of completing the sale of
certain of its prospective mineral fee lands in North America. The assets
involved in the sale include approximately 3.3 million net acres, primarily in
Texas, Louisiana, Mississippi, Arkansas and Alabama. The Company has agreed to
sell these properties for approximately $190 million in cash. The purchase price
will be adjusted to reflect the effective date of October 1, 2003. The sale is
expected to close by the end of the second quarter 2004, and the Company expects
to record an after-tax gain of approximately $65 million.
The Company also held for sale its interests in the Trans-Andean oil pipeline,
which transports crude oil from Argentina to Chile.
Details of the assets classified as held for sale, as of March 31, 2004, are
presented below:
E&P Midstream &
Millions of dollars North America Marketing Total
- --------------------------------------------------------------------------------
Assets
Properties - net $ 67 $ - $ 67
Other assets - 38 38
- --------------------------------------------------------------------------------
Total assets $ 67 $ 38 $ 105
================================================================================
11. Postemployment Benefit Plans
The Company has numerous plans worldwide that provide employees with retirement
benefits. The Company also has medical plans that provide health care benefits
for eligible employees and many of its retired employees. Most of the Company's
plans covering employees outside of North America are unfunded and resulting
liabilities are extinguished on a "pay as you go" basis.
The components of net periodic benefit cost for the Company's pension and
postretirement medical plans for the periods ending March 31, 2004 and March 31,
2003 were:
Pension Benefits Other Benefits
----------------- --------------
Millions of dollars 2004 2003 2004 2003
- -------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 8 $ 7 $ 1 $ 1
Interest cost 20 20 7 6
Expected return on plan assets (19) (21) - -
Amortization of:
Transition obligation - - - -
Prior service cost 1 1 - -
Net actuarial (gains) losses 16 15 3 3
Curtailment and settlement (gains) losses - - - -
Cost of special separation benefits - - - -
- --------------------------------------------------------------------------------
Net periodic pension and
other benefit cost (credit) $26 $ 22 $ 11 $ 10
================================================================================
-9-
The assumed weighted-average rates used to determine the preceding net periodic
benefit costs were:
Pension Benefits Other Benefits
----------------- --------------
Weighted-average assumptions 2004 2003 2004 2003
- --------------------------------------------------------------------------------
Discount rates 6.00% 6.74% 6.00% 6.75%
Rates of salary increases 4.91% 4.93% 4.99% 4.99%
Expected returns on plan assets 8.00% 8.40% N/A N/A
In the quarter ended March 31, 2004, no contributions were made to the U.S.
Qualified Retirement Plan. The Company is not required under existing funding or
tax regulations to make any cash contributions to its U.S. Qualified Retirement
Plan in 2004. The Company may elect, however, to make voluntary contributions to
its U.S. Qualified Retirement Plan during the remainder of 2004.
The Company previously disclosed in its financial statements for the year ended
December 31, 2003 that it expected to contribute approximately $4 million to its
Supplemental Executive Retirement plans, approximately $17 million to its
foreign pension plans and approximately $27 million to its worldwide
postretirement medical plans in 2004. As of March 31, 2004, the Company does not
anticipate that actual contributions for the full year 2004 for said plans will
vary materially from these forecasted levels.
12. Long Term Debt
The Company's total consolidated debt, including current maturities, was $3.26
billion at March 31, 2004, compared with $2.88 billion at the end of 2003. The
increase reflects the recognition of $538 million in 6-1/4% convertible junior
subordinated debentures, payable to the Trust, as long term debt, replacing the
$522 million convertible preferred securities of the Trust (see note 2 and note
13 for further detail). During the first three months of 2004, the Company
retired $173 million in 6.375% notes and paid down $20 million of medium-term
notes, which matured during the quarter. These decreases were partially offset
by $40 million in new borrowings relating to Phase 1 development of the
Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea.
13. Variable Interest Entities
In 1996, Unocal exchanged 10,437,873 newly issued 6-1/4% trust convertible
preferred securities of Unocal Capital Trust, a Delaware statutory trust, for
shares of a then-outstanding issue of convertible preferred stock. Unocal
acquired the convertible preferred securities, which had an aggregate
liquidation value of $522 million, from the Trust, together with 322,821 common
securities of the Trust, which had an aggregate liquidation value of $16
million, in exchange for $538 million principal amount of 6-1/4% convertible
junior subordinated debentures of Unocal. The Trust was accounted for as a
100-percent-owned consolidated finance subsidiary of Unocal, with the debentures
and payments thereon by Unocal to the Trust eliminated in the consolidated
financial statements. Pursuant to FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities," as revised in December 2003 (see note 2), the
Company deconsolidated the Trust in the first quarter of 2004. As a result, the
$522 million obligation for the convertible preferred securities was removed
from the consolidated balance sheet and replaced by $538 million in 6-1/4%
convertible junior subordinated debentures of Unocal payable to the Trust. In
addition, the Company recorded its $16 million investment in the Trust in
investments and long-term receivables-net on the consolidated balance sheet.
Effective in the first quarter of 2004, interest payments on the debentures are
now recorded as interest expense on the consolidated earnings statement. In
prior periods, payments to the holders of the preferred securities were reported
as a separate line item on the consolidated earnings statement.
-10-
14. Accrued Abandonment, Restoration and Environmental Liabilities
At March 31, 2004, the Company had accrued $732 million in estimated abandonment
and restoration costs as liabilities. At December 31, 2003, the Company had
accrued $710 million in estimated abandonment and restoration costs. The
increase in the liability account from December 31, 2003 was due to accrued
pre-tax accretion expense of $11 million, $10 million in revisions to existing
estimates and $5 million in new abandonment liabilities recorded during the
period. Abandonment liability settlements totaled $4 million during the first
three months of 2004.
The Company's reserve for environmental remediation obligations at March 31,
2004 totaled $244 million, of which $116 million was included in current
liabilities. This compared with $252 million at December 31, 2003, of which $118
million was included in current liabilities.
15. Commitments and Contingencies
The Company has contingent liabilities with respect to material existing or
potential claims, lawsuits and other proceedings, including those involving
environmental, tax, guarantees and other matters, certain of which are discussed
more specifically below. The Company accrues liabilities when it is probable
that future costs will be incurred and such costs can be reasonably estimated.
Such accruals are based on developments to date, the Company's estimates of the
outcomes of these matters and its experience in contesting, litigating and
settling other matters. As the scope of the liabilities becomes better defined,
there will be changes in the estimates of future costs, which could have a
material effect on the Company's future results of operations and financial
condition or liquidity.
Environmental matters
The Company continues to move forward to address environmental issues for which
it is responsible. The Company, in cooperation with regulatory agencies and
others, follows procedures that it has established to identify and cleanup
contamination associated with its past operations. The Company is subject to
loss contingencies pursuant to federal, state, local and foreign environmental
laws and regulations. These include existing and possible future obligations to
investigate the effects of the release or disposal of certain petroleum,
chemical and mineral substances at various sites; to remediate or restore these
sites; to compensate others for damage to property and natural resources, for
remediation and restoration costs and for personal injuries; and to pay civil
penalties and, in some cases, criminal penalties and punitive damages. These
obligations relate to sites owned by the Company or others and are associated
with past and present operations, including sites at which the Company has been
identified as a potentially responsible party ("PRP") under the federal
Superfund laws and comparable state laws. Liabilities are accrued when it is
probable that future costs will be incurred and such costs can be reasonably
estimated. However, in many cases, investigations are not yet at a stage where
the Company is able to determine whether it is liable or, even if liability is
determined to be probable, to quantify the liability or estimate a range of
possible exposure.
In such cases, the amounts of the Company's liabilities are indeterminate due to
the potentially large number of claimants for any given site or exposure, the
unknown magnitude of possible contamination, the imprecise and conflicting
engineering evaluations and estimates of proper clean-up methods and costs, the
unknown timing and extent of the corrective actions that may be required, the
uncertainty attendant to the possible award of punitive damages, the recent
judicial recognition of new causes of action, the present state of the law,
which often imposes joint and several and retroactive liabilities on PRPs, the
fact that the Company is usually just one of a number of companies identified as
a PRP, or other reasons.
-11-
As disclosed in note 14, at March 31, 2004, the Company had accrued $244 million
for estimated future environmental assessment and remediation costs at various
sites where liabilities for such costs are probable and reasonably estimable.
The Company may also incur additional liabilities in the future at sites where
remediation liabilities are probable but future environmental costs are not
presently reasonably estimable because the sites have not been assessed or the
assessments have not advanced to the stage where costs are reasonably estimable.
At those sites where investigations or feasibility studies have advanced to the
stage of analyzing feasible alternative remedies and/or ranges of costs, the
Company estimates that it could incur possible additional remediation costs
aggregating approximately $215 million. The amount of such possible additional
costs reflects the aggregate of the high ends of the ranges of costs of feasible
alternatives identified by the Company for those sites with respect to which
investigation or feasibility studies have advanced to the stage of analyzing
such alternatives. However, such estimated possible additional costs are not an
estimate of the total remediation costs beyond the amounts reserved, because
there are sites where the Company is not yet in a position to estimate all, or
in some cases any, possible additional costs. Both the amounts reserved and
estimates of possible additional costs may change in the near term, and in some
cases could change substantially, as additional information becomes available
regarding the nature and extent of site contamination, required or agreed-upon
remediation methods and other actions by government agencies and private
parties.
During the three months period ended March 31, 2004, cash payments of $24
million were applied against the reserves and $16 million in provisions were
added to the reserves. Possible additional remediation costs increased by $10
million during the first three months period of 2004. The accrued costs and the
estimated possible additional costs are shown below for four categories of
sites:
At March 31, 2004
----------------------------
Estimated Possible
Millions of dollars Reserve Additional Costs
- --------------------------------------------------------------------------------
Superfund and similar sites $ 15 $ 15
Active Company facilities 28 30
Company facilities sold with retained liabilities
and former Company-operated sites 90 85
Inactive or closed Company facilities 111 85
- --------------------------------------------------------------------------------
Total $ 244 $ 215
================================================================================
The time frames over which the amounts included in the reserve may be paid
extend from the near term to several years into the future. The sites included
in the above categories are in various stages of investigation and remediation;
therefore, the related payments against the existing reserve will be made in
future periods. Also, some of the work is dependent upon reaching agreements
with regulatory agencies and/or other third parties on the scope of remediation
work to be performed, who will perform the work, the timing of the work, who
will pay for the work and other factors that may have an impact on the timing of
the payments for amounts included in the reserve. For some sites, the
remediation work will be performed by other parties, such as the current owners
of the sites, and the Company has a contractual agreement to pay a share of the
remediation costs. For these sites, the Company generally has less control over
the timing of the work and consequently the timing of the associated payments.
Based on available information, the Company estimates that the majority of the
amounts included in the reserve will be paid within the next three to five
years.
At the sites where the Company has contractual agreements to share remediation
costs with third parties, the reserve reflects the Company's estimated shares of
those costs. In many of the oil and gas sites, remediation cost sharing is
included in joint venture agreements that were made with third parties during
the original operation of the sites. In many cases where the Company sold
facilities or a business to a third party, sharing of remediation costs for
those sites may be included in the sales agreement.
-12-
Contamination at the sites of the "Superfund and similar sites" category was the
result of the disposal of substances at these sites by one or more PRPs.
Contamination of these sites could be from many sources, of which the Company
may be one. The Company has been notified that it is a PRP at the sites included
in this category. At the sites where the Company has not denied liability, the
Company's contribution to the contamination at these sites was primarily from
operations identified below.
The "Active Company facilities" category includes oil and gas fields and mining
operations. The oil and gas sites are primarily contaminated with crude oil, oil
field waste and other petroleum hydrocarbons. Contamination at the active mining
sites was principally the result of the impact of mined material on the
groundwater and/or surface water at these sites.
The "Company facilities sold with retained liabilities and former
Company-operated sites" and "Inactive or closed Company facilities" categories
include former Company refineries, transportation and distribution facilities
and service stations. The required remediation of these sites is mainly for
petroleum hydrocarbon contamination as the result of leaking tanks, pipelines or
other equipment or impoundments that were used in these operations. Also,
included in these categories are former oil and gas fields that the Company no
longer operates. In most cases, these sites are contaminated with crude oil, oil
field waste and other petroleum hydrocarbons. Contamination at other sites in
these categories of sites was the result of former industrial chemical and
polymers manufacturing and distribution facilities, agricultural chemical retail
businesses and ferromolybdenum production operations.
Superfund and similar sites - Included in this category of sites are:
o The McColl site in Fullerton, California
o The Operating Industries site in Monterey Park, California
o The Casmalia Waste site in Casmalia, California
At March 31, 2004, the Company had received notifications from the U.S.
Environmental Protection Agency ("EPA") that the Company may be a PRP at 24
sites and may share certain liabilities at these sites. Of the total, four sites
are under investigation and/or litigation and the Company's potential liability
is not presently determinable and for one site, the Company has denied
responsibility. At one site, the Company's potential liability appears to be de
minimis. Of the remaining 18 sites, where the Company has concluded that
liability is probable and to the extent costs can be reasonably estimated, a
reserve of $11 million has been established for future remediation and
settlement costs.
Various state agencies and private parties had identified 22 other similar PRP
sites. Seven sites are under investigation and/or litigation and the Company's
potential liability is not presently determinable and at three sites the
Company's potential liability appears to be de minimis. Where the Company has
concluded that liability is probable and to the extent costs can be reasonably
estimated at the remaining 12 sites, a reserve of $4 million has been
established for future remediation and settlement costs.
The sites discussed above exclude 125 sites where the Company's liability has
been settled, or where the Company has no evidence of liability and there has
been no further indication of liability by government agencies or third parties
for at least a 12-month period.
The Company does not consider the number of sites for which it has been named a
PRP as a relevant measure of liability. Although the liability of a PRP is
generally joint and several, the Company is usually just one of numerous
companies designated as a PRP. The Company's ultimate share of the remediation
costs at those sites often is not determinable due to many unknown factors. The
solvency of other responsible parties and disputes regarding responsibilities
may also impact the Company's ultimate costs.
Active Company facilities - Included in this category are:
o The Molycorp molybdenum mine in Questa, New Mexico
o The Molycorp lanthanide facility in Mountain Pass, California
o Alaska oil and gas properties
-13-
The Company has a reserve of $28 million for estimated future costs of remedial
orders, corrective actions and other investigation, remediation and monitoring
obligations at certain operating facilities and producing oil and gas fields.
The Company recorded provisions of $2 million during the first three months of
2004 and made payments of $2 million for this category of sites.
Company facilities sold with retained liabilities and former Company-operated
sites - Company facilities sold with retained liabilities include:
o West Coast refining, marketing and transportation sites
o Auto/truckstop facilities in various locations in the U.S.
o Industrial chemical and polymer sites in the South,
Midwest and California
o Agricultural chemical sites in the West and Midwest.
In each sale, the Company retained a contractual remediation or indemnification
obligation and is responsible only for certain environmental problems that
resulted from operations prior to the sale. The reserve represents estimated
future costs for remediation work: identified prior to the sale of these sites;
included in negotiated agreements with the buyers of these sites where the
Company retained certain levels of remediation liabilities; and/or identified in
subsequent claims made by buyers of the properties. Former Company-operated
sites include service stations, distribution facilities and oil and gas fields
that were previously operated but not owned by the Company.
The Company has an aggregate reserve of $90 million for this group of sites.
During the first three months of 2004, provisions of $10 million for the
"Company facilities sold with retained liabilities and former Company-operated
sites" category were recorded. These provisions were primarily for approximately
100 sites where the Company had operated service stations, bulk plants or
terminals. The provisions were based on new and revised cost estimates that were
developed for these sites in the first quarter of 2004. Payments of $19 million
were made during the first three months of 2004 for sites in this category.
Inactive or closed Company facilities - The major sites in this category are:
o The Guadalupe oil field on the central California coast
o The Molycorp Washington and York facilities in Pennsylvania
o The Beaumont Refinery in Texas.
A reserve of $111 million has been established for these types of facilities.
During the first three months of 2004, the Company accrued $4 million related to
sites in this category primarily for the Beaumont Refinery site. A provision was
recorded by the Company for the updated cost estimates to close impoundments
used in the former operations at this site. In the first quarter of 2004, final
design work and related detailed cost estimates to close these impoundments were
completed. The Company also received final approval of a permit for these
projects from the Texas Commission on Environmental Quality. Payments of $3
million were made during the first three months of 2004 for sites in this
category.
The Company is subject to federal, state and local environmental laws and
regulations, including the Comprehensive Environmental Response, Compensation
and Liability Act of 1980 ("CERCLA"), as amended, the Resource Conservation and
Recovery Act ("RCRA") and laws governing low level radioactive materials. Under
these laws, the Company is subject to existing and/or possible obligations to
remove or mitigate the environmental effects of the disposal or release of
certain chemical, petroleum and radioactive substances at various sites.
Corrective investigations and actions pursuant to RCRA and other federal, state
and local environmental laws are being performed at the Company's facility in
Beaumont, Texas, a former agricultural chemical facility in Corcoran,
California, and Molycorp's facility in Washington, Pennsylvania. In addition,
Molycorp is required to decommission its Washington and York facilities in
Pennsylvania pursuant to the terms of their respective radioactive source
materials licenses and decommissioning plans.
The Company also must provide financial assurance for future closure and
post-closure costs of its RCRA-permitted facilities and for decommissioning
costs at facilities that are under radioactive source materials licenses.
Pursuant to a 1998 settlement agreement between the Company and the State of
California (and the subsequent stipulated judgment entered by the Superior
Court), the Company must provide financial
-14-
assurance for anticipated costs of remediation activities at its inactive
Guadalupe oil field. As previously discussed, remediation reserves for these
sites are included in the "Inactive or closed Company facilities" category and
totaled $99 million at March 31, 2004. At those sites where investigations or
feasibility studies have advanced to the stage of analyzing alternative remedies
and/or ranges of costs, the Company estimates that it could incur possible
additional remediation costs aggregating approximately $55 million. Although any
possible additional costs for these sites are likely to be incurred at different
times and over a period of many years, the Company believes that these
obligations could have a material adverse effect on the Company's results of
operations but are not expected to be material to the Company's consolidated
financial condition or liquidity.
The total environmental remediation reserve recorded on the consolidated balance
sheet represents the Company's estimates of assessment and remediation costs
based on currently available facts, existing technology and presently enacted
laws and regulations. The remediation cost estimates, in many cases, are based
on plans recommended to the regulatory agencies for approval and are subject to
future revisions. The ultimate costs to be incurred could exceed the total
amounts reserved. The reserve will be adjusted as additional information becomes
available regarding the nature and extent of site contamination, required or
agreed-upon remediation methods and other actions by government agencies and
private parties. Therefore, amounts reserved may change substantially in the
near term.
The Company maintains insurance coverage intended to reimburse the cost of
damages and remediation related to environmental contamination resulting from
sudden and accidental incidents under current operations. The purchased
coverages contain specified and varying levels of deductibles and payment
limits. Although certain of the Company's contingent legal exposures enumerated
above are uninsurable either due to insurance policy limitations, public policy
or market conditions, management believes that its current insurance program
significantly reduces the possibility of an incident causing a material adverse
financial impact to the Company.
Certain Litigation and Claims
Nuevo Energy Claim: Nuevo Energy Company has paid Unocal $39.95 million to
settle an ongoing dispute (U.S.D.C. Central District of California Case No.
03-4664 (RCx)) regarding contingent payments for 2002 and subsequent years owed
by Nuevo to the Company under the terms of the 1996 Asset Purchase Agreement
pursuant to which Nuevo purchased substantially all of the Company's operating
California oil and gas properties. The Company received the full amount of the
settlement payment on April 30, 2004. Under the settlement, the contingent
payment agreement has been terminated. Nuevo has also released Unocal from
liability for $10.8 million Nuevo claimed it paid to Unocal by mistake.
Agrium Litigation: In June 2002, a lawsuit was filed against the Company by
Agrium Inc., a Canadian corporation, and Agrium U.S. Inc., its U. S. subsidiary,
in the Superior Court of the State of California for the County of Los Angeles
(Agrium U.S. Inc. and Agrium Inc. v. Union Oil Company of California, Case
No. BC275407) (the "Agrium Claim"). Simultaneously, the Company filed suit
against the Agrium entities ("Agrium") in the U.S. District Court for the
Central District of California (Union Oil Company of California v. Agrium, Inc.,
Case No. 02-04518 NM) (the "Company Claim"). The Company subsequently removed
the Agrium Claim to the U.S. District Court for the Central District of
California (Case No. 02-04769 NM). The federal court has since remanded the
Agrium Claim to the California Superior Court. In addition, the Company has
initiated arbitration concerning the Gas Purchase and Sale Agreement ("GPSA")
between the Company and Agrium U.S. Inc. (AAA Case No. 70 198 00539 02)
(the "Arbitration").
The Agrium Claim alleges numerous causes of action relating to Agrium's purchase
from the Company of a nitrogen-based fertilizer plant on the Kenai Peninsula,
Alaska, in September 2000. The primary allegations involve the Company's
obligation to supply natural gas to the plant pursuant to the GPSA. Agrium
alleges that the Company misrepresented the amount of natural gas reserves
available for sale to the plant as of the closing of the transaction and that
the Company has failed to develop additional natural gas reserves for sale to
the plant. Agrium also alleges that the Company misrepresented the condition of
the general effluent sewer at the plant and made misrepresentations regarding
other environmental matters.
-15-
Agrium seeks damages in an unspecified amount for breach of such representations
and warranties, as well as for alleged misconduct by the Company in operating
and managing certain oil and gas leases and other facilities. One of its expert
witnesses, however, has calculated Agrium's damages in a range between $292
million and $708 million, depending upon different models. The Company disagrees
with the witness. Agrium also seeks declaratory relief for the calculation of
payments under a "Retained Earnout" covenant in the Purchase and Sale Agreement
for the plant (the "PSA") that entitles the Company to certain contingent
payments based on the price of ammonia subsequent to the September 2000 closing.
The complaint includes demands for punitive damages and attorneys' fees.
In September 2002, Agrium amended its complaint to add allegations that the
Company breached certain conditions of the September 2000 closing, breached
certain indemnification obligations, and violated the pertinent health and
safety code. Agrium also asked for recission of the sale of the fertilizer
plant, in addition, or as an alternative, to money damages. In addition, Agrium
seeks a declaration by the arbitral panel that has been convened (see below)
that natural gas from Unocal's Ninilchik, Happy Valley fields "or elsewhere"
should be delivered to the plant to meet Unocal's alleged obligations under the
GPSA.
In the Company Claim, the Company seeks declaratory relief in its favor against
the allegations of Agrium set forth above and for judgment on the Retained
Earnout in the amount of $17 million plus interest accrued subsequent to May
2002. Unocal is also seeking over $900,000 in reliability bonuses due under the
GPSA and reimbursement of over $5 million in royalties paid to the State of
Alaska.
The GPSA contains a contractual limit on liquidated damages of $25 million per
year, not to exceed a total of $50 million over the life of the agreement. In
addition, the PSA contains a limit on damages of $50 million. The Company
believes it has a meritorious defense to each of the Agrium claims, but that in
any event its exposure to damages for all disputes is limited by the agreements.
Agrium alleges that it is entitled to recover damages in excess of those
amounts.
On July 16, 2003, the court approved an agreed stipulation between the parties
to submit all issues under the GPSA to arbitration. The arbitration proceedings
are scheduled to commence May 24, 2004.
Petrobangla Claim: In July 2002, the Company's subsidiary Unocal Bangladesh
Blocks Thirteen and Fourteen, Ltd. ("Unocal Blocks 13 and 14 Ltd.") received a
letter from the Bangladesh Oil, Gas & Mineral Corporation ("Petrobangla")
claiming, on behalf of the Bangladesh government and Petrobangla, compensation
allegedly due in the amount of $685 million for 246 BCF of recoverable natural
gas allegedly "lost and damaged" in a 1997 blowout and ensuing fire during the
drilling by Occidental Petroleum Corporation (known at that time in Bangladesh
as Occidental of Bangladesh Ltd.) ("OBL"), as operator, of the Moulavi Bazar #1
("MB #1") exploration well on the Blocks 13 and 14 PSC area in Northeast
Bangladesh. The Company and OBL believe that the claim vastly overstates the
amount of recoverable gas involved in the blowout.
Consistent with worldwide industry contracting practice, there was no provision
in the PSC for compensating the Bangladesh government or Petrobangla for
resources lost during the contractor's operations. Even if some form of
compensation were due, the Company and OBL believe that settlement compensation
for the blowout was fully addressed in a 1998 Supplemental Agreement to the PSC
(the "Supplemental Agreement"), which, among other matters, waived OBL's then
50-percent contractor's share (as well as the then 50-percent contractor's share
held by the Company's Unocal Bangladesh, Ltd., subsidiary ("Unocal Bangladesh"))
of entitlement to the recovery of costs incurred in the drilling of the MB #1
and the blowout, waived their right to invoke force majeure in connection with
the blowout, and reduced by five percentage points their contractors' profit
share (with a concomitant increase in Petrobangla's profit share) of future
production from the sands encountered by the MB #1 well to a drill depth of 840
meters or, if the blowout sand reservoir were not present or development is not
feasible deemed commercial, from other commercial fields in the Moulavi Bazar
"ring-fenced" area of Block 14. Consequently, the Company and OBL consider the
matter closed and Unocal Blocks 13 and 14 Ltd. has advised Petrobangla that no
additional compensation is warranted. By Writ Petition Affidavit dated March 24,
2003, a concerned citizen filed suit in the Bangladesh lower court (Alam v.
Bangladesh, Petrobangla, Department of Environment, and Unocal Bangladesh, Ltd.,
Supreme Court of Bangladesh, High Court Division, Writ Petition No. 2461 of
2003) on the basis of the MB #1 blowout. The Company was notified of the suit on
May 26, 2003 when it received the court's order to show cause why the
Supplemental Agreement should not be declared illegal and cancelled on account
of its having
-16-
been executed without lawful authority, and why Unocal Bangladesh
should not be directed to stop exploration until it compensates for the MB#1
blowout. No hearing is currently scheduled on the matter, and the Company
believes the action is not well founded.
Tax matters
The Company believes it has adequately provided in its accounts for tax items
and issues not yet resolved. Several prior material tax issues are unresolved.
Resolution of these tax issues impacts not only the year in which the items
arose, but also the Company's tax situation in other tax years. With respect to
1979-1994 taxable years, all issues raised for these years have now been
tentatively settled with the Appeals division of the Internal Revenue Service
("IRS") as well as the Tax Court, including the carryback of a 1993 net
operating loss ("NOL") to tax year 1984 and resultant credit adjustments. The
1993 NOL resulted from certain specified liability losses described in Internal
Revenue Code Section 172. Since the audit of the 1979-1994 taxable years
resulted in a net overpayment of income taxes for the period, the Joint
Committee on Taxation of the U.S Congress must review the claim. Once
notification from the Joint Committee is received, taxable years 1979-1994 will
be effectively closed as a single package, pending entry of final decisions in
Tax Court for the docketed years, to assure that interest is properly computed
under the complex rules, which govern netting of interest. All such developments
have been considered in the Company's accounts. The 1995-1997 taxable years are
before the Appeals division of the IRS. The 1998- 2001 taxable years are now
before the Exam division of the IRS.
Guarantees Related to Assets or Obligations of Third Parties
The Company has agreed to indemnify certain third parties for particular future
remediation costs that may be incurred for properties held by these parties. The
guarantees were established when the Company either leased property from or sold
property to these third parties. The properties may or may not have been
contaminated by various Company operations. Where it has been or will be
determined that the Company is responsible for contamination, the guarantees
require the Company to pay the costs to remediate the sites to specified cleanup
levels or to levels that will be determined in the future.
The maximum potential amount of future payments that the Company could be
required to make under these guarantees is indeterminate primarily due to the
following: the indefinite term of the majority of these guarantees; the unknown
extent of possible contamination; uncertainties related to the timing of the
remediation work; possible changes in laws governing the remediation process;
the unknown number of claims that may be made; changes in remediation
technology; and the fact that most of these guarantees lack limitations on the
maximum potential amount of future payments.
The Company has accrued probable and reasonably estimable assessment and
remediation costs for the locations covered under these guarantees. These
amounts are included in the "Company facilities sold with retained liabilities
and former Company-operated sites" category of the Company's reserve for
environmental remediation obligations. At March 31, 2004, the reserve for this
category totaled $90 million. For those sites where investigations or
feasibility studies have advanced to the stage of analyzing feasible alternative
remedies and/or ranges of costs, the Company estimates that it could incur
possible additional remediation costs aggregating approximately $85 million. See
the discussion elsewhere in this footnote for additional information regarding
this category.
The Company has a construction completion guarantee related to debt financing
arrangements for the Baku-Tbilisi-Ceyhan ("BTC") pipeline project. The Company
has an equity interest in the development of this pipeline from Baku, Azerbaijan
through Georgia to the Mediterranean port of Ceyhan, Turkey. The Company's
maximum potential future payments under the guarantee are estimated to be $310
million. The debt is secured by transportation proceeds from production of the
Azeri field of the Caspian Sea. The debt is non-recourse upon financial
completion certification, which is expected by 2009. As of March 31, 2004, the
Company has recorded a liability of $19 million as the estimated value of this
guarantee.
The Company has also guaranteed the debt of certain other entities accounted for
by the equity method. The majority of this debt matures ratably through the year
2014. The maximum potential amount of future payments the Company could be
required to make is approximately $17 million.
-17-
In the ordinary course of business, the Company has agreed to indemnify cash
deficiencies for certain domestic pipeline joint ventures, which the Company
accounts for on the equity method. These guarantees are considered in the
Company's analysis of overall risk. Since most of these agreements do not
contain spending caps, it is not possible to quantify the amount of maximum
payments that may be required. Nevertheless, the Company believes the payments
would not have a material adverse impact on its financial condition or
liquidity.
Financial Assurance for Unocal Obligations
In the normal course of business, the Company has performance obligations that
are secured, in whole or in part, by surety bonds or letters of credit. These
obligations primarily cover self-insurance, site restoration, dismantlement and
other programs where governmental organizations require such support. These
surety bonds and letters of credit are issued by financial institutions and are
required to be reimbursed by the Company if drawn upon. At March 31, 2004, the
Company had obtained various surety bonds for $188 million. These surety bonds
included a bond for $76 million securing the Company's performance under a fixed
price natural gas sales contract for the delivery of 72 billion cubic feet of
gas over a ten-year period that began in January of 1999 and will end in
December of 2008 and $112 million in various other routine performance bonds
held by local, city, state and federal agencies. The Company also had obtained
$75 million in standby letters of credit at March 31, 2004, of which $15 million
represented additional collateral related to the aforementioned fixed price
natural gas sales contract. The Company has entered into indemnification
obligations in favor of the providers of these surety bonds and letters of
credit.
The Company has various other guarantees for approximately $525 million.
Approximately $134 million of the $525 million in guarantees represent financial
assurance given by the Company on behalf of its Molycorp subsidiary relating to
permits covering operations and discharges from its Questa, New Mexico,
molybdenum mine. The Company's financial assurance is for the completion of
temporary closure plans (required only upon cessation of operations) and other
obligations required under the terms of the permits. The costs associated with
the financial assurance are based on estimations provided by agencies of the
state of New Mexico.
Guarantees for approximately $300 million of the $525 million would require the
Company to obtain a surety bond or a letter of credit or establish a trust fund
if its credit rating were to drop below investment grade -- that is BBB- or Baa3
from Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
respectively.
Approximately $150 million of the surety bonds, letters of credit and other
guarantees that the Company is required to obtain or issue reflect obligations
that are already included on the consolidated balance sheet in other current
liabilities and other deferred credits. The surety bonds, letters of credit and
other guarantees may also reflect some of the possible additional remediation
liabilities discussed earlier in this note.
Other matters
The Company has a lease agreement relating to the Discoverer Spirit deepwater
drillship, with a current minimum daily rate of approximately $226,000. The
future remaining minimum lease payment obligation was approximately $120 million
at March 31, 2004. The contract will expire on September 18, 2005.
The Company also has other contingent liabilities with respect to litigation,
claims and contractual agreements arising in the ordinary course of business.
Based on management's assessment of the ultimate amount and timing of possible
adverse outcomes and associated costs, none of such matters is presently
expected to have a material adverse effect on the Company's consolidated
financial condition, liquidity or results of operations.
-18-
16. Financial Instruments and Commodity Hedging
Interest rate contracts - The Company enters into interest rate swap contracts
to manage its debt with the objective of minimizing the volatility and magnitude
of the Company's borrowing costs. The Company may also enter into interest rate
option contracts to protect its interest rate positions, depending on market
conditions. At March 31, 2004, the Company had approximately $22 million of
after-tax deferred losses in accumulated other comprehensive income on the
consolidated balance sheet related to cash flow hedges of interest rate
exposures through September 2012. Of this amount, $3 million in after-tax losses
are expected to be reclassified to the consolidated earnings statement during
the next twelve months.
Foreign currency contracts - Various foreign exchange currency forward, option
and swap contracts are entered into by the Company from time to time to manage
its exposures to adverse impacts of foreign currency fluctuations on recognized
obligations and anticipated transactions. At March 31, 2004, the Company had no
material deferred amounts in accumulated other comprehensive income on the
consolidated balance sheet related to foreign currency contracts.
Commodity hedging activities - The Company uses hydrocarbon derivatives to
mitigate its overall exposure to fluctuations in hydrocarbon commodity prices.
Ineffectiveness for cash flow and fair value hedges in the first quarter of 2004
was immaterial. At March 31, 2004, the Company had approximately $33 million of
after-tax deferred losses in accumulated other comprehensive income on the
consolidated balance sheet related to cash flow hedges for future commodity
sales for the period beginning April 2004 through December 2004. All of the
after-tax losses are expected to be reclassified to the consolidated earnings
statement during 2004.
Fair values for debt and other long-term instruments - The estimated fair values
of the Company's long-term debt were $3.60 billion at March 31, 2004. Fair
values were based on the discounted amounts of future cash outflows using the
rates offered to the Company for debt with similar remaining maturities.
-19-
17. Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiary Union Oil. Such guarantees are full and unconditional
and no subsidiaries of Unocal or Union Oil guarantee these securities.
As a result of adopting FASB Interpretation No. 46 (revised December 2003) (see
note 2 and 13 for further detail), the Company deconsolidated Unocal Capital
Trust (the "Trust") effective January 1, 2004.
The following tables present condensed consolidating financial information for
(a) Unocal (Parent), (b) Union Oil (Parent) and (c) on a combined basis, the
subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all of the
Company's operations are conducted by Union Oil and its subsidiaries. The 2003
tables also present the Trust, as part of the condensed consolidating financial
information.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended March 31, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ 326 $ 1,717 $ (206) $ 1,837
Interest, dividends and miscellaneous income - 4 8 (1) 11
Gain on sales of assets - 24 20 - 44
- ---------------------------------------------------------------------------------------------------------------------
Total revenues - 354 1,745 (207) 1,892
Costs and other deductions
Purchases, operating and other expenses 2 229 1,146 (206) 1,171
Depreciation, depletion and amortization - 63 169 - 232
Impairments - 3 2 - 5
Dry hole costs - 17 8 - 25
Interest expense 8 26 8 (1) 41
- ---------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 338 1,333 (207) 1,474
Equity in earnings of subsidiaries 278 238 - (516) -
Earnings from equity investments - 1 36 - 37
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 268 255 448 (516) 455
- ---------------------------------------------------------------------------------------------------------------------
Income taxes (1) (23) 205 - 181
Minority interests - - 5 - 5
- ---------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 269 278 238 (516) 269
- ---------------------------------------------------------------------------------------------------------------------
Net earnings $ 269 $ 278 $ 238 $ (516) $ 269
=====================================================================================================================
-20-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
For the Three Months Ended March 31, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 512 $ 1,690 $ (427) $ 1,775
Interest, dividends and miscellaneous income - 8 11 2 (10) 11
Gain (loss) on sales of assets - - (9) 12 - 3
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues - 8 514 1,704 (437) 1,789
Costs and other deductions
Purchases, operating and other expenses 2 - 282 1,211 (427) 1,068
Depreciation, depletion and amortization - - 106 154 - 260
Impairments - - - - - -
Dry hole costs - - 52 19 - 71
Interest expense 8 - 30 10 (10) 38
Distributions on convertible preferred securities - 8 - - - 8
- ----------------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 8 470 1,394 (437) 1,445
Equity in earnings of subsidiaries 142 - 181 - (323) -
Earnings from equity investments - - 3 40 - 43
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 132 - 228 350 (323) 387
- ----------------------------------------------------------------------------------------------------------------------------------
Income taxes (2) - 31 139 - 168
Minority interests - - - 2 - 2
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 134 - 197 209 (323) 217
Earnings from discontinued operations - - - - - -
Cumulative effect of accounting changes - - (55) (28) - (83)
- ----------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 134 $ - $ 142 $ 181 $ (323) $ 134
==================================================================================================================================
-21-
CONDENSED CONSOLIDATED BALANCE SHEET
At March 31, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ 332 $ 428 $ - $ 760
Accounts and notes receivable - net 118 236 1,005 (132) 1,227
Inventories - 8 181 (79) 110
Other current assets - 121 33 - 154
- ----------------------------------------------------------------------------------------------------------------------
Total current assets 118 697 1,647 (211) 2,251
Properties - net - 1,988 6,414 (3) 8,399
Other assets including goodwill 5,446 5,332 1,919 (11,211) 1,486
- ----------------------------------------------------------------------------------------------------------------------
Total assets $5,564 $ 8,017 $ 9,980 $ (11,425) $ 12,136
======================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ 290 $ 929 $ (118) $ 1,101
Current portion of long-term debt - 5 57 - 62
Other current liabilities 55 270 574 (16) 883
- ----------------------------------------------------------------------------------------------------------------------
Total current liabilities 55 565 1,560 (134) 2,046
Long-term debt 538 1,806 855 - 3,199
Deferred income taxes - (208) 929 - 721
Accrued abandonment, restoration
and environmental liabilities - 388 472 - 860
Other deferred credits and liabilities - 692 324 (3) 1,013
Minority interests - - 40 7 47
Stockholders' equity 4,971 4,774 5,800 (11,295) 4,250
- ----------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $5,564 $ 8,017 $ 9,980 $ (11,425) $ 12,136
======================================================================================================================
-22-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 45 $ 358 $ - $ 404
Accounts and notes receivable - net 94 - 360 946 (108) 1,292
Inventories - - 15 205 (79) 141
Other current assets (1) - 127 28 - 154
- ------------------------------------------------------------------------------------------------------------------------------
Total current assets 94 - 547 1,537 (187) 1,991
Properties - net - - 2,012 6,315 (3) 8,324
Other assets including goodwill 4,645 541 5,433 1,564 (10,700) 1,483
- ------------------------------------------------------------------------------------------------------------------------------
Total assets $4,739 $ 541 $ 7,992 $ 9,416 $ (10,890) $ 11,798
==============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 335 $ 831 $ (94) $ 1,072
Current portion of long-term debt - - 193 55 - 248
Other current liabilities 52 3 299 427 (16) 765
- ------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 52 3 827 1,313 (110) 2,085
Long-term debt - - 1,811 824 - 2,635
Deferred income taxes - - (184) 888 - 704
Accrued abandonment, restoration
and environmental liabilities - - 390 454 - 844
Other deferred credits and liabilities - - 654 309 (3) 960
Minority interests - - - 32 7 39
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 4,687 16 4,494 5,596 (10,784) 4,009
- ------------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,739 $ 541 $ 7,992 $ 9,416 $ (10,890) $ 11,798
==============================================================================================================================
-23-
CONDENSED CONSOLIDATED CASH FLOWS
For the Three Months Ended March 31, 2004
Non-
Unocal Union Oil Guarantor
Millions of dollars (Parent) (Parent) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ - $ 523 $ 227 $ - $ 750
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - (63) (297) - (360)
Proceeds from sales of assets
and discontinued operations - 20 52 - 72
Return of capital from affiliate company - - 52 - 52
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - (43) (193) - (236)
- ---------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt - (193) 36 - (157)
Dividends paid on common stock (52) - - - (52)
Proceeds from issuance of common stock 51 - - - 51
- ---------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (1) (193) 36 - (158)
- ---------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (1) 287 70 - 356
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period 1 45 358 - 404
- ---------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ 332 $ 428 $ - $ 760
=====================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the Three Months Ended March 31, 2003
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 51 $ - $ 221 $ 413 $ - $ 685
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (95) (334) - (429)
Proceeds from sales of assets
and discontinued operations - - 42 24 - 66
- --------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (53) (310) - (363)
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (97) 13 - (84)
Dividends paid on common stock (52) - - - - (52)
Minority interests - - - (2) - (2)
Other 1 - - 3 - 4
- --------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (51) - (97) 14 - (134)
- --------------------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents - - 71 117 - 188
- --------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - (18) 186 - 168
- --------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 53 $ 303 $ - $ 356
================================================================================================================================
-24-
18. Segment Data
The Company has made changes in the reporting of its segments from the reporting
utilized in the 2003 Annual Report on Form 10-K, as amended, as detailed in the
following tables. The Company's reportable segments are: Exploration and
Production, Midstream & Marketing, and Geothermal. General corporate overhead,
unallocated costs and other miscellaneous operations, including real estate,
carbon and minerals and those businesses that were sold or being phased-out, are
included under the Corporate and Other heading.
The Company's Exploration and Production segment has simplified its North
America presentation by combining the Alaska business unit with the U.S. Lower
48 business to form the U.S. geographic designation. In the International
geographic designation, the Company will present two sub-categories: Asia and
Other versus the previous categories of Far East and Other. In addition, the
former Trade segment has been combined with the Midstream segment to form the
Midstream & Marketing segment.
- ---------------------------------------------------------------------------------------------------------------------
Segment Information Exploration & Production
For the Three Months North America International
Ended March 31, 2004
- ---------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Intl Total E&P
- ---------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 305 $ 71 $ 376 $ 352 $ 57 $ 409 $ 785
Other income (loss) (a) 10 - 10 1 1 2 12
Inter-segment revenues 206 32 238 102 - 102 340
- ---------------------------------------------------------------------------------------------------------------------
Total 521 103 624 455 58 513 1,137
Earnings (loss) from equity investments - - - 10 - 10 10
Earnings (loss) from continuing operations 116 12 128 158 17 175 303
Earnings from discontinued operations (net) - - - - - - -
Cumulative effect of accounting changes - - - - - - -
- ---------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 116 12 128 158 17 175 303
Assets (at March 31, 2004) 3,213 1,310 4,523 3,440 844 4,284 8,807
- ---------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
- ---------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 981 $ 40 $ - $ - $ - $ 31 $ 1,837
Other income (loss) (a) 5 32 - 6 - - 55
Inter-segment revenues 2 - - - - (342) -
- ---------------------------------------------------------------------------------------------------------------------
Total 988 72 - 6 - (311) 1,892
Earnings (loss) from equity investments 16 1 - - - 10 37
Earnings (loss) from continuing operations 23 37 (27) (32) (16) (19) 269
Earnings from discontinued operations (net) - - - - - - -
Cumulative effect of accounting changes - - - - - - -
- ---------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 23 37 (27) (32) (16) (19) 269
Assets (at March 31, 2004) 1,133 548 - - - 1,648 12,136
- ---------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
-25-
- ---------------------------------------------------------------------------------------------------------------------
Segment Information Exploration & Production
For the Three Months North America International
Ended March 31, 2003
- ---------------------------------------------------------------------------------------------------------------------
Millions of dollars U.S. Canada Total N.A. Asia Other Total Intl Total E&P
- ---------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 227 $ 58 $ 285 $ 332 $ 30 $ 362 $ 647
Other income (loss) (a) 3 - 3 - - - 3
Inter-segment revenues 388 38 426 91 - 91 517
- --------------------------------------------------------------------------------------------------------------------
Total 618 96 714 423 30 453 1,167
Earnings (loss) from equity investments 3 - 3 9 4 13 16
Earnings (loss) from continuing operations 126 24 150 132 10 142 292
Cumulative effect of accounting changes (b) (32) 4 (28) 13 - 13 (15)
- ---------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 94 28 122 145 10 155 277
Assets (at December 31, 2003) 3,315 1,324 4,639 3,377 765 4,142 8,781
- ---------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Net Environ-
Marketing Admin & Interest mental &
General Expense Litigation Other(b)
- ---------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 1,061 $ 35 $ - $ - $ - $ 32 $ 1,775
Other income (loss) (a) - - - 4 - 7 14
Inter-segment revenues 2 - - - - (519) -
- ---------------------------------------------------------------------------------------------------------------------
Total 1,063 35 - 4 - (480) 1,789
Earnings (loss) from equity investments 16 1 - - - 10 43
Earnings (loss) from continuing operations 9 12 (23) (31) (17) (25) 217
Cumulative effect of accounting changes (b) (2) - - - - (66) (83)
- ---------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 7 12 (23) (31) (17) (91) 134
Assets (at December 31, 2003) 1,097 611 - - - 1,309 11,798
- ---------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Net of tax (benefit) $48
(c) Includes eliminations and consolidation adjustments.
-26-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion and analysis of the financial condition and results of
operations of the Company should be read in conjunction with Management's
Discussion and Analysis in Item 7 of Unocal's 2003 Annual Report on Form 10-K,
as amended, and the consolidated financial statements and related notes therein.
OVERVIEW
In the first quarter of 2004, the Company met most of its operational and
financial targets. Production was slightly below the forecasted range due to
several factors, including an unforeseen two-month pipeline shutdown in the Gulf
of Mexico because of a vessel accident involving a Mobile Bay pipeline. In
addition, the West Seno facility in Indonesia had a planned two-week shutdown
during the quarter. International production was less than anticipated due to
lower volumes from Production Sharing Contracts due to higher prices. Thailand
operations had an excellent quarter as natural gas sales continued to be above
contract minimums. The higher Thai production partially offset the lower than
expected production volumes in Indonesia and the Gulf of Mexico. Expenses and
capital budgets were in the expected ranges and drill bit success continued in
Indonesia.
Some of the more significant operational highlights from the first quarter of
2004 are listed below:
- - Drilled significant deepwater discovery in the Gulf of Mexico (Puma) and had
successful appraisal wells in Indonesia (Gehem and Gula).
- - Drilling of two high-impact deepwater wells - Tobago and Mad Dog Deep - in the
Gulf of Mexico.
- - Continued ramp-up of production on the deepwater West Seno project in
Indonesia, although slower than forecast.
- - Continued discussion and negotiation on terms for supplying higher volumes of
natural gas in both the short and long term in Thailand.
- - Submitted development plan to sell natural gas from the Bibiyana field for
Petrobangla, the state oil company, in Bangladesh.
- - Received $60 million in cash from the sale of the Sarulla geothermal project
to Indonesia's state electric utility.
- - Progressed on construction of the Phase 1 and 2 developments of the Azerbaijan
International Operating Company ("AIOC") project in the Caspian Sea; first oil
at the wellhead is expected in late 2004 or early 2005 for Phase 1.
- - Completed approximately 60 percent of the construction on the
Baku-Tbilisi-Ceyhan ("BTC") export pipeline from the Caspian Sea.
- - Reached agreement to sell certain fee mineral interests in the U.S. for
approximately $190 million cash.
CONSOLIDATED RESULTS
In 2004, the Company's Exploration and Production segment has simplified its
North America presentation by combining the Alaska business unit with the U.S.
Lower 48 to form the U.S. geographic designation. In the International
geographic designation, the Company will present two sub-categories: Asia and
Other versus the previous categories of Far East and Other. In addition, the
former Trade segment has been combined with the Midstream segment to form the
Midstream & Marketing segment. See note 18 to the consolidated financial
statements in Item 1 of this report for revisions in the Company's reportable
segments.
For the Three Months
Ended March 31,
--------------------------
Millions of dollars 2004 2003
- --------------------------------------------------------------------------------
Earnings from continuing operations $ 269 $ 217
Cumulative effect of accounting changes - (83)
- --------------------------------------------------------------------------------
Net earnings $ 269 $ 134
================================================================================
-27-
Earnings From Continuing Operations
Earnings from continuing operations were $269 million in the first quarter of
2004, which was an increase of $52 million compared to the same quarter a year
ago. The increase was primarily due to higher realized worldwide natural gas
prices, which increased net earnings by approximately $40 million. Higher
International liquids production also contributed approximately $40 million in
higher earnings, primarily from higher Indonesia and Thailand production. Dry
hole costs were lower compared with the previous year, primarily due to lower
drilling activity, increasing net earnings by approximately $30 million.
Included in the current period are dry hole costs for the House Payment and
Myrtle Beach exploratory wells in the Gulf of Mexico. Gains from asset sales,
which included the sale of the Company's rights and interests in the Sarulla
geothermal project in Indonesia, added another $30 million to net earnings. The
Company's worldwide average realized natural gas price, which included a gain of
17 cents per Mcf from hedging activities in the current quarter, was $4.00 per
Mcf. This was an increase of 10 cents per Mcf from the $3.90 per Mcf realized
during the same period a year ago, which included a loss of 27 cents per Mcf
from hedging activities. In the current quarter, the Company's worldwide average
realized liquids price was $ 30.64 per Bbl, which was an increase of 65 cents
per Bbl from the same period a year ago. The Company's hedging program lowered
the average realized liquids price by $1.00 per Bbl in the current quarter while
the prior year quarter included a loss of 50 cents per Bbl from hedging
activities.
These positive variance factors were partially offset by lower North America
production, which reduced net earnings by approximately $75 million in the first
quarter of 2004 compared with the same period a year ago. North America liquids
production averaged 72,000 Bbl/d in the first quarter of 2004, down from 88,000
Bbl/d a year ago, while natural gas production averaged 599 MMcf/d down from 858
MMcf/d for 2003. Most of the production decline was due to the divestiture of
various properties in the Gulf of Mexico, onshore U.S. and Canada and pipeline
down time in the Mobile Bay area of the Gulf of Mexico.
After-tax environmental and litigation expenses for the Company were $23 million
in the first quarter of 2004, compared with $17 million in 2003.
The effective income tax rate for the current quarter was 40 percent compared
with 43 percent for the first quarter of 2003, reflecting lower overall average
foreign income tax expense due to a mix of earnings from countries with lower
tax rates as compared to same period a year ago.
Cumulative Effect of Accounting Changes
In the first quarter of 2003, the Company recorded a non-cash $83 million
after-tax charge for the cumulative effect of a change in accounting principle
related to the initial adoption of Statement of Financial Accounting Standards
("SFAS") No. 143, "Accounting for Asset Retirement Obligations."
Revenues
Revenues from continuing operations for the first quarter of 2004 were $1.89
billion compared with $1.79 billion for the same period a year ago. The increase
primarily reflected higher crude oil and natural gas prices. This was partially
offset by lower North America production.
-28-
OPERATING HIGHLIGHTS UNOCAL CORPORATION
1st Q 1st Q
---------------------
2004 2003
- ------------------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
U.S. (a) 55 70
Canada 17 18
- ------------------------------------------------------------------------------------------
Total liquids 72 88
Natural gas - dry basis (million cubic feet)
U.S. (a) 515 761
Canada 84 97
- ------------------------------------------------------------------------------------------
Total natural gas 599 858
North America Average Prices (excluding hedging activities) (b)
Liquids (per barrel)
U. S. $ 32.66 $ 31.39
Canada $ 28.51 $ 28.44
Average $ 31.71 $ 30.77
Natural gas (per mcf)
U. S. $ 5.04 $ 5.86
Canada $ 5.38 $ 5.64
Average $ 5.09 $ 5.83
- ------------------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (b)
Liquids (per barrel)
U. S. $ 29.87 $ 30.29
Canada $ 28.51 $ 28.44
Average $ 29.56 $ 29.90
Natural gas (per mcf)
U. S. $ 5.57 $ 5.24
Canada $ 5.08 $ 5.33
Average $ 5.50 $ 5.25
- -----------------------------------------------------------------------------------------
(a)Includes proportional interests in production of equity investees.
(b)Excludes gains/losses on derivative positions not accounted for as
hedges and ineffective portions of hedges.
-29-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
1st Q 1st Q
---------------------
2004 2003
- ------------------------------------------------------------------------------------------
International Net Daily Production (c)
Liquids (thousand barrels)
Asia 66 56
Other (a) 20 20
- ------------------------------------------------------------------------------------------
Total liquids 86 76
Natural gas - dry basis (million cubic feet)
Asia 884 960
Other (a) 25 22
- ------------------------------------------------------------------------------------------
Total natural gas 909 982
International Average Prices (d)
Liquids (per barrel)
Asia $ 31.44 $29.69
Other $ 32.12 $32.44
Average $ 31.57 $30.11
Natural gas (per mcf)
Asia $ 2.97 $ 2.76
Other $ 4.29 $ 4.15
Average $ 2.98 $ 2.77
- ------------------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (c)
Liquids (thousand barrels) 158 164
Natural gas - dry basis (million cubic feet) 1,508 1,840
Barrels oil equivalent (thousands) 409 471
Worldwide Average Prices (excluding hedging activities) (b)
Liquids (per barrel) $ 31.64 $30.49
Natural gas (per mcf) $ 3.83 $ 4.17
Worldwide Average Prices (including hedging activities) (b)
Liquids (per barrel) $ 30.64 $29.99
Natural gas (per mcf) $ 4.00 $ 3.90
- ------------------------------------------------------------------------------------------
(a)Includes proportional interests in production of equity investees.
(b)Excludes gains/losses on derivative positions not accounted for as
hedges and ineffective portions of hedges.
(c)International production is presented utilizing the economic interest method.
(d)International did not have any hedging activities.
-30-
BUSINESS SEGMENT RESULTS
See note 18 to the consolidated financial statements in Item 1 of this report
for details of the Company's new reportable segments, which are now organized as
follows:
Exploration and Production
The Company engages in oil and gas exploration, development and production
worldwide. The results of this segment are discussed under the geographical
breakdown of North America and International:
North America - Included in this category are the U.S. and Canada oil and gas
operations.
After-tax earnings totaled $128 million in the first quarter of 2004 compared to
$150 million for the same period a year ago, which was a decrease of $22
million. The decrease was primarily due to lower production that was partially
offset by higher natural gas prices and lower dry hole costs. Lower natural gas
and liquids production reduced after-tax earnings by approximately $75 million
while higher natural gas prices increased net earnings by approximately $20
million. Lower dry hole costs increased net earnings by approximately $25
million in the first quarter of 2004 primarily from lower Gulf of Mexico
drilling activity. The first quarter of 2004 results also included a $15 million
litigation settlement related to a previous asset sale and additional gains of
$6 million related to the 2003 sale of certain assets in the Gulf of Mexico.
International - The Company's International operations encompass oil and gas
exploration and production activities outside of North America. The Company,
through its International subsidiaries, operates or participates in production
operations in Thailand, Indonesia, Myanmar, Bangladesh, the Netherlands,
Azerbaijan, the Democratic Republic of Congo and Brazil.
After-tax earnings totaled $175 million in the first quarter of 2004 compared to
$142 million in the first quarter of 2003. The increase was primarily due to
about $40 million in higher liquids production and approximately $15 million in
higher natural gas prices. Higher liquids production was primarily due to the
West Seno production in Indonesia, which began in the second half of 2003. These
positive factors were partially offset by lower natural gas production from
Myanmar and Bangladesh, which reduced after-tax earnings by about $15 million.
Midstream & Marketing
The Midstream & Marketing segment is comprised of the Company's equity interests
in certain petroleum pipeline companies, wholly-owned pipelines and terminals
throughout the U.S., the Company's North America gas storage business and the
Company's organization that markets the majority of the Company's worldwide
liquids production and North American natural gas production. In addition, the
marketing organization conducts the Company's trading activities involving
hydrocarbon derivative instruments, for which hedge accounting is not used, to
exploit anticipated opportunities arising from commodity price fluctuations. The
marketing organization also purchases limited amounts of physical inventories
for energy trading purposes when arbitrage opportunities arise. These commodity
risk-management and trading activities are subject to internal restrictions,
including value at risk limits, which measure the Company's potential loss from
likely changes in market prices
Earnings from continuing operations totaled $23 million in the current quarter
compared to $9 million in the first quarter of 2003. The higher results
primarily reflect gains from crude oil and natural gas trading activities, which
were positively impacted by volatile commodity prices.
The segment's sales and operating revenues were $981 million in the current
quarter compared to $1.06 billion in the same quarter a year ago. Included in
these totals were sales from marketing activities totaling $833 million in the
current quarter compared to $920 million in the same quarter a year ago,
representing approximately 45 percent and 52 percent of the Company's total
sales and operating revenues for the first quarters of 2004 and 2003,
respectively. The decrease in sales from marketing activities was primarily due
to lower domestic natural gas and crude oil revenues attributable to property
sales in 2003. Higher international crude oil volumes partially offset these
decreases.
-31-
Geothermal
The Geothermal segment produces geothermal steam for power generation, with
operations in the Philippines and Indonesia. The segment's activities also
include the operation of geothermal steam-fired power plants in Indonesia and
equity interests in gas-fired power plants in Thailand.
Earnings from continuing operations totaled $37 million in the current quarter
compared to $12 million in the same period a year ago. This increase was
primarily due to the $21 million after-tax gain from the sale of the Company's
rights and interests in the Sarulla geothermal project on the island of Sumatra,
Indonesia.
Corporate and Other
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate, carbon and mineral businesses), other
corporate unallocated costs (including environmental and litigation expenses)
and net interest expense.
The results for the current quarter were a loss of $94 million compared to a
loss of $96 million in the same period a year ago. The current quarter reflects
approximately $4 million in improved results from the Company's real estate
business. After-tax expenses for environmental and litigation matters for the
current quarter were $20 million compared to $17 million in the same period a
year ago.
LIQUIDITY and CAPITAL RESOURCES
Based on current commodity prices and current development projects, the Company
expects cash generated from operating activities, asset sales and cash on hand
in 2004 to be sufficient for the remainder of 2004 to cover its operating and
capital spending requirements and to meet expected dividend payments and to pay
down debt. The Company has substantial borrowing capacity to enable it to meet
unanticipated cash requirements. Cash and cash equivalents on hand totaled $760
million at March 31, 2004, up from $404 million at the end of 2003.
Cash flows from operating activities, including working capital and other
changes, were $744 million for the first three months ended March 31, 2004,
compared with $685 million for the same period a year ago. The increase
principally reflected the effects of higher worldwide commodity prices. The
positive impact from higher prices was partially offset by the negative impact
from lower North America production, compared to the same period a year ago.
Changes in working capital during the first quarter of 2004 reflect the receipt
of $35 million relating to a federal income tax refund related to estimated
payments for the 2003 tax year, receipt of payment from the Indonesian
government in settlement of disputed value added taxes paid by the Company in
prior years and a reduction in receivables from joint venture partners in the
U.S. as a result of asset sales in 2003.
Pre-tax proceeds from asset sales were $72 million for the three months ended
March 31, 2004. The Company received about $60 million from the sale of its
rights and interests in the Sarulla geothermal project in Indonesia. The Company
also received $12 million from the sale of various properties in the Gulf of
Mexico. Pre-tax proceeds from asset sales were $66 million for the three months
ended March 31, 2003 primarily from the sale of various properties in Canada,
onshore U.S. and the Gulf of Mexico.
Capital expenditures were $360 million for the first three months of 2004
compared with $429 million in the same period a year ago. Capital expenditures
for 2004 are still forecasted at approximately $2.01 billion. In the first three
months of 2004, the Company's capital expenditures included approximately $185
million for the development of undeveloped proved oil and gas reserves,
primarily in Indonesia, Azerbaijan, Thailand and the deepwater Gulf of Mexico.
In the first quarter of 2004, cash flows from investing activities also included
$52 million representing a return of capital as a result of the completion of
the BTC financing which closed in February 2004. The BTC Pipeline Company is
financing up to 70 percent of the pipeline's cost. The Company has an 8.9
percent equity interest in the pipeline company.
-32-
The Company's total consolidated debt, including current maturities, was $3.26
billion at March 31, 2004, compared with $2.88 billion at the end of 2003. The
increase in total debt outstanding reflects the recognition of $538 million in
6-1/4% convertible junior subordinated debentures as debt replacing the Trust's
convertible preferred securities on the balance sheet (see notes 2 and 13 to the
consolidated financial statements). During the first three months of 2004, the
Company also retired $173 million in 6.375% notes and paid down $20 million of
medium-term notes that matured during the quarter. These decreases were
partially offset by $40 million in funding relating to Phase 1 development of
the Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea.
The Company has two primary credit facilities in place: a $400 million 364-day
credit agreement and a $600 million 5-year credit agreement, maturing October
2006. No borrowings were outstanding under either facility at March 31, 2004.
The Company's ability to borrow under these facilities is subject to the
accuracy of certain representations and warranties and the absence of any events
of default that the Company believes are customary for such facilities.
The agreements provide for the termination of the loan commitments and require
the prepayment of all outstanding borrowings in the event that (1) any person or
group becomes the beneficial owner of more than 30 percent of the then
outstanding voting stock of Unocal other than in a transaction having the
approval of Unocal's board of directors, at least a majority of which are
continuing directors, or (2) if continuing directors shall cease to constitute
at least a majority of the board. The agreements do not have drawdown
restrictions or prepayment obligations in the event of a credit rating
downgrade. Both agreements limit the Company's total debt to total
capitalization ratio to 70 percent (total capitalization is defined as total
debt plus total equity, with the Company's convertible junior subordinated
debentures excluded from total debt and included as equity in the ratio
calculation.) In addition, the Company also has a 3-year $295 million Canadian
dollar-denominated non-revolving credit facility with a variable rate of
interest. At March 31, 2004, the borrowing under the Canadian credit facility
translated to $223 million, using applicable foreign exchange rates.
The Company relies on the commercial paper market, its accounts receivable
securitization program and its revolving credit facilities to cover near-term
borrowing requirements. At March 31, 2004, the Company did not have an
outstanding balance under its accounts receivable securitization program. The
Company also had in place a universal shelf registration statement as of March
31, 2004, with an unutilized balance of approximately $1.539 billion, which is
available for the future issuance of other debt and/or equity securities
depending on the Company's needs and market conditions. From time to time, the
Company may also look to fund some of its long-term projects using other
financing sources, including multilateral and bilateral agencies.
Maintaining investment-grade credit ratings, that is "BBB- / Baa3" and above
from Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
respectively, is a significant factor in the Company's ability to raise
short-term and long-term financing. As a result of the Company's current
investment grade ratings, the Company has access to both the commercial paper
and bank loan markets. The Company currently has a BBB+ / Baa2 credit rating by
Standard & Poor's and Moody's, respectively, and an A-2 / Prime-2 for its
commercial paper ratings. Moody's and Standard & Poor's outlooks, as of the date
of the filing of this report, remained stable for the Company's long term debt
and commercial paper ratings. The Company does not believe it has a significant
exposure to liquidity risk in the event of a credit rating downgrade.
Off-Balance Sheet Arrangements
The Company has a construction completion guarantee related to debt financing
associated with its equity interest in the development of the BTC pipeline
project. The maximum potential future payments under the guarantee is estimated
to be $310 million. Extending guarantees to creditors allows the project to
reduce its borrowing costs. The Company is not the primary beneficiary in this
arrangement. See note 15 to the consolidated financial statements for a detailed
discussion.
-33-
ENVIRONMENTAL MATTERS
The Company is committed to operating its business in a manner that is
environmentally responsible. This commitment is fundamental to the Company's
core values. As part of this commitment, the Company has procedures in place to
audit and monitor its environmental performance. In addition, it has implemented
programs to identify and address environmental risks throughout the Company.
Costs associated with identified environmental obligations have been accrued in
a reserve for such obligations. At March 31, 2004, the Company's reserves for
environmental remediation obligations totaled $244 million, of which $116
million was included in current liabilities. During the first three months
period of 2004, cash payments of $24 million were applied against the reserves
and $16 million in provisions were added to the reserves. The Company may also
incur additional liabilities at sites where remediation liabilities are probable
but future environmental costs are not presently reasonably estimable because
the sites have not been assessed or the assessments have not advanced to stages
where costs are reasonably estimable. At those sites where investigations or
feasibility studies have advanced to the stage of analyzing feasible alternative
remedies and/or ranges of costs, the Company estimates that it could incur
possible additional remediation costs aggregating approximately $215 million.
The reserve amounts and estimated possible additional costs are grouped into the
following four categories:
At March 31, 2004
----------------------------
Estimated Possible
Millions of dollars Reserve Additional Costs
- --------------------------------------------------------------------------------
Superfund and similar sites $ 15 $ 15
Active Company facilities 28 30
Company facilities sold with retained liabilities
and former Company-operated sites 90 85
Inactive or closed Company facilities 111 85
- --------------------------------------------------------------------------------
Total $ 244 $ 215
================================================================================
Also, see notes 14 and 15 to the consolidated financial statements in Item 1 of
this report for additional information on environmental related matters.
During the first three months of 2004, provisions of $10 million were recorded
for the "Company facilities sold with retained liabilities and former
Company-operated sites" category. These provisions were primarily for
approximately 100 sites where the Company had operated service stations, bulk
plants or terminals. The provisions were based on new and revised cost estimates
that were developed for these sites in the first quarter of 2004.
The Company accrued $4 million related to sites in the "Inactive or closed
Company facilities" category during the first three months of 2004 primarily for
the Company's former refinery in Beaumont, Texas. A provision was recorded for
the updated cost estimates to close impoundments used in the former operations
at this site. In the first quarter of 2004, final design work and related
detailed cost estimates to close these impoundments were completed. The Company
also received final approval of a permit for these projects from the Texas
Commission on Environmental Quality.
In the first three months of 2004, estimated possible additional costs in excess
of amounts included in the reserves for remediation obligations increased by $10
million. The increase was for sites in the "Company facilities sold with
retained liabilities and former Company-operated sites" category. The higher
costs were primarily for a former oil field in Michigan and for former service
station sites at various locations. Estimated possible additional costs for the
former Michigan oil field were increased for the cost of assessments and
remediation that may need to be performed on certain areas within the site that
may have been contaminated by the former oil field operation. These costs are
based on an evaluation being performed at the site in the first quarter of 2004.
Higher possible additional costs for the former service station sites are based
on new and revised estimates of the upper end of remediation costs ranges that
were developed during the first three months of 2004.
-34-
OUTLOOK
Realized prices for liquids and North America natural gas are a significant
driver of financial performance for the Company. Energy prices are expected to
remain volatile due to a variety of fundamental and market perception factors
including variability of the weather on a year to year basis, worldwide demand,
crude oil and natural gas inventory levels, production quotas set by OPEC,
current and future worldwide political instability, especially events concerning
Iraq, worldwide security and other factors. The Company has secured fixed price
"hedges" to mitigate some of that volatility, primarily relating to a portion of
its 2004 North America natural gas and crude oil production.
The economic situation in Asia, where most of the Company's international
activity is centered, is showing positive signs. The Company looks at the
natural gas market in Asia as one of its major strategic investments.
The Company's estimate for production for the second quarter of 2004 is between
410,000 and 420,000 BOE per day. The current estimate for full-year 2004
production is about 425,000 BOE per day. The full-year 2004 outlook reflects
lower cost recovery barrels from PSCs due to higher commodity prices, slower
than expected production ramp-up from the West Seno field in Indonesia and the
lack of success in the exploration drilling program on the Gulf of Mexico deep
shelf.
The Company's outlook of important 2004 activities is as follows:
Exploration and Production - North America
United States
o In the deep water region of the Gulf of Mexico, the Mad Dog development
project will be nearing completion by the end of 2004. Initial production
is expected in early 2005. The Company has a 15.6 percent working interest.
o Another Gulf of Mexico deep water development moving forward in 2004 is the
K-2 field, in which the Company has a 12.5 percent working interest.
Initial production is expected in March 2005.
o Gulf of Mexico exploration will be focused on the deep water. In May, the
Company's exploratory well on the Tobago prospect in Alaminos Canyon Block
859 was a discovery. The well, in which the Company has a 40.01 percent
working interest found about 50 net feet of oil pay. The discovery was one
of several wells that have been drilled to date in the Alaminos Canyon area
to evaluate the development potential for the Perdido Foldbelt. The Company
is also currently participating in the drilling of a deep test exploratory
well in the Mad Dog field. Other appraisal activities expected in 2004
include follow-up wells on the Company's Saint Malo and Puma discoveries
in the deep water Gulf of Mexico.
o In Alaska, first production from the Company's Happy Valley discovery is
planned for late 2004 upon completion of an extension of the Kenai Kachemak
Pipeline. Other natural gas prospects in the southern Kenai Peninsula are
targeted for exploration. The Company expects to drill two or three of them
in 2004.
Exploration and Production - International
Asia
Thailand:
o Thailand's electricity market continues to grow at around 9 percent per
annum. Additional supplies of natural gas to meet that growth have been
constrained by pipeline capacity. Recent de-bottlenecking activities on the
two existing pipelines in the Gulf of Thailand should allow the Company an
opportunity for increased production in 2004 and 2005, prior to the
expected completion of the third pipeline in 2006.
-35-
o Significant new crude oil production is anticipated from Phase 2
development of the Platong, Yala, Surat, and Plamuk areas. Development work
has advanced in 2004, with an additional 20 MBbl/d of gross crude oil
expected in the second half of 2005.
o The Company anticipates signing final agreements in 2004 for the extension
of existing natural gas sales agreements and expansion of contract
quantities by 15 percent by 2006, and another 50 percent by 2010-2012.
o The Arthit field's natural gas sales agreement has been signed and
development work is expected during 2004 with first production anticipated
in 2006.
Indonesia:
o At the West Seno field, the Company expects to drill an additional 14 wells
by the end of this year and expects to achieve a gross exit rate at the end
of 2004 for Phase 1 of 35 MBOE/d.
o The Company is starting to solidify its development plans for the first
Deep Water natural gas development. Development will likely be around two
major hubs: first production is expected to come from the Gendalo field to
the south where eight appraisal wells have been drilled. The Company is
aiming for late 2006 or early 2007 for first gas. The second complex will
probably be the Rangass-Gehem oil and gas development and will follow with
production in 2007 or 2008. A third appraisal well is currently drilling on
Gehem's northern edge, which is very near to the southern part of the
Ranggas field. The Company will also be drilling a deep Ranggas well to
target oil in formations similar to those in deep Gehem.
o Exploration and appraisal drilling will continue in 2004 in the deep water
Kutei Basin. This drilling activity will test for crude oil in deeper
horizons below the Company's past natural gas discoveries. These tests will
also allow the Company to certify additional natural gas volumes, which
will be used to secure increased allocations of the new Bontang sales
contracts, the majority of which are anticipated in 2010 and beyond.
Vietnam:
o The Company has recently signed a Heads of Agreement with PetroVietnam for
natural gas development. The Company will be fulfilling its drilling
commitments by the end of 2004 and is continuing to work to bring Vietnam
gas to market between 2008 and 2010.
China:
o Both development and exploration activity is expected in 2004 on the
Company's PSC areas in the Xihu Trough off the coast of Shanghai.
o Evaluation of technical information will proceed on existing wells that
were drilled in the past. Once the evaluation is complete, a final
development plan will be determined.
o Exploration drilling is anticipated with up to six "wildcat" and appraisal
wells expected in 2004. The first appraisal well has been completed and the
first exploration well is currently being drilled. A successful drilling
campaign is essential to achieve minimum commercial reserves for the Phase
I development. If the exploration and appraisal programs prove sufficient
reserves, commercial natural gas production could begin in late 2005.
Bangladesh:
o Construction and development drilling on the Moulavi Bazar field is
progressing, with first production expected in the first half of 2005.
Moulavi Bazar is expected to have peak production of 70 to 100 MMcf/d.
-36-
o The Company is in negotiations for a third natural gas sales agreement in
Bangladesh covering the Bibiyana field. The Company expects to conclude
negotiations later in 2004. The Bibiyana field is capable of being
developed in stages, which could provide Bangladesh with natural gas
resources in the short, medium and long term time frames.
Other International
Azerbaijan:
o Progress is continuing in 2004 on the development of the BP operated AIOC
project. The Company expects sanctioning of Phase 3 in the third quarter of
this year. Phase 3, which is the deepwater portion of the project, is the
final phase of full field development. Gross production is expected to ramp
up to more than 200 MBbl/d in 2005, rising to 700 MBbl/d in 2007 and over 1
million Bbl/d by 2009. The Company has a 10.28 percent working interest.
Midstream & Marketing
o In parallel with the AIOC field development work in Azerbaijan, the BTC
pipeline is expected to be fully operational in the second half of 2005.
The portions of the pipeline through Azerbaijan and Georgia are expected to
be complete and ready for line-fill in the first quarter of 2005. The
Company's interest in this pipeline is 8.9 percent. The BTC pipeline will
transport the crude oil from the AIOC field to the Turkish port of Ceyhan
and will have a capacity of 1 million Bbl/d.
o The Company completed the sale of its Cal Ven Pipeline system located in
Alberta, Canada, for approximately $19 million in May 2004.
FUTURE ACCOUNTING CHANGES
See Note 2 to the consolidated financial statements for information about recent
accounting pronouncements.
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements, which may be identified by
words such as "expects," "anticipates," "intends," "plans," "believes,"
"estimates," "forecasts," "will" and words of similar import. These
forward-looking statements include, but are not limited to, statements regarding
contingent liabilities for environmental, litigation and tax matters and under
guarantees and indemnities, expected exploratory drilling and project
developments, capital expenditures, the Company's ability to fund its activities
from available cash, borrowings and financings, production rates and timing,
commodity prices and future negotiations, sales and transactions.
These statements are not guarantees of future performance or outcomes. They are
based upon Unocal's current expectations and beliefs and are subject to a number
of known and unknown risks and uncertainties that could cause actual results to
differ materially from those described in the forward-looking statements. Actual
results could differ materially as a result of factors including changes in
commodity prices; the levels of the company's oil and gas production; the extent
of the company's operating cash flow and other capital resources available to
fund its capital expenditures; regulatory, political, geological, operating and
economic considerations; performance by third parties of their contractual
obligations; and other factors discussed in Unocal's 2003 Annual Report on Form
10-K, as amended, and subsequent reports filed with the U.S. Securities and
Exchange Commission (SEC). Copies of the Company's SEC filings are available
from the Company by calling 800-252-2233 or from the SEC by calling
800-SEC-0330. The reports are also available on the Unocal web site,
www.unocal.com.
Unocal undertakes no obligation to update the forward-looking statements in this
report to reflect future events or circumstances. All such statements are
expressly qualified in their entirety by this cautionary statement.
-37-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk generally represents the risk that losses may occur in the values of
financial instruments as a result of changes in interest rates, foreign currency
exchange rates and commodity prices. As part of its overall risk management
strategies, the Company uses derivative financial instruments to manage and
reduce risks associated with these factors. The Company also trades hydrocarbon
derivative instruments, such as futures contracts, swaps and options to exploit
anticipated opportunities arising from commodity price fluctuations.
The Company determines the fair values of its derivative financial instruments
primarily based upon market quotes of exchange traded instruments. Most futures
and options contracts are valued based upon direct exchange quotes or industry
published price indices. Some instruments with longer maturity periods require
financial modeling to accommodate calculations beyond the horizons of available
exchange quotes. These models calculate values for outer periods using current
exchange quotes (i.e., forward curve) and assumptions regarding interest rates,
commodity and interest rate volatility and, in some cases, foreign currency
exchange rates. While the Company feels that current exchange quotes and
assumptions regarding interest rates and volatilities are appropriate factors to
measure the fair value of its longer termed derivative instruments, other
pricing assumptions or methodologies may lead to materially different results in
some instances.
Interest Rate Risk - From time to time the Company temporarily invests its
excess cash in short-term interest-bearing securities issued by high-quality
issuers. Company policies limit the amount of investment in securities of any
one financial institution. Due to the short time the investments are outstanding
and their general liquidity, these instruments are classified as cash
equivalents in the consolidated balance sheet and do not represent a material
interest rate risk to the Company. The Company's primary market risk exposure to
changes in interest rates relates to the Company's long-term debt obligations.
The Company manages its exposure to changing interest rates principally through
the use of a combination of fixed and floating rate debt. Interest rate risk
sensitive derivative financial instruments, such as swaps or options may also be
used depending upon market conditions.
The Company evaluated the potential effect that near term changes in interest
rates would have had on the fair value of its interest rate risk sensitive
financial instruments at March 31, 2004. Assuming a ten percent decrease in the
Company's weighted average borrowing costs at March 31, 2004, the potential
increase in the fair value of the Company's debt obligations and associated
interest rate derivative instruments, including the debt obligations and
associated interest rate derivative instruments of its subsidiaries, would have
been approximately $89 million at March 31, 2004.
-38-
Foreign Exchange Rate Risk - The Company conducts business in various parts of
the world and in various foreign currencies. To limit the Company's foreign
currency exchange rate risk related to operating income, foreign sales
agreements generally contain price provisions designed to insulate the Company's
sales revenues against adverse foreign currency exchange rates. In most
countries, energy products are valued and sold in U.S. dollars and foreign
currency operating cost exposures have not been significant. In other countries,
the Company is paid for product deliveries in local currencies but at prices
indexed to the U.S. dollar. These funds, less amounts retained for operating
costs, are converted to U.S. dollars as soon as practicable. The Company's
Canadian subsidiaries are paid in Canadian dollars for their crude oil and
natural gas sales and have outstanding Canadian-dollar denominated debt.
From time to time the Company may purchase foreign currency options or enter
into foreign currency swap or foreign currency forward contracts to limit the
exposure related to its foreign currency debt or other obligations. At March 31,
2004, the Company had various foreign currency forward contracts outstanding
related to operations in Thailand and the Netherlands. The Company evaluated the
effect that near term changes in foreign exchange rates would have had on the
fair value of the Company's combined foreign currency position related to its
outstanding foreign currency swaps, forward contracts and foreign-currency
denominated debt. Assuming an adverse change of ten percent in foreign exchange
rates at March 31, 2004, the potential decrease in fair value of the foreign
currency swaps, foreign currency forward contracts and foreign-currency
denominated debt of the Company and its subsidiaries would have been
approximately $33 million at March 31, 2004.
Commodity Price Risk - The Company is a producer, purchaser, marketer and trader
of certain hydrocarbon commodities such as crude oil and condensate, natural gas
and refined products and is subject to the associated price risks. The Company
uses hydrocarbon price-sensitive derivative instruments ("hydrocarbon
derivatives"), such as futures contracts, swaps, collars and options to mitigate
its overall exposure to fluctuations in hydrocarbon commodity prices. The
Company may also enter into hydrocarbon derivatives to hedge contractual
delivery commitments and future crude oil and natural gas production against
price exposure. The Company also actively trades hydrocarbon derivatives,
primarily exchange regulated futures and options contracts, subject to internal
policy limitations.
The Company uses a variance-covariance value at risk model to assess the market
risk of its hydrocarbon derivatives. Value at risk represents the potential loss
in fair value the Company would experience on its hydrocarbon derivatives, using
calculated volatilities and correlations over a specified time period with a
given confidence level. The Company's risk model is based upon current market
data and uses a three-day time interval with a 97.5 percent confidence level.
The model includes offsetting physical positions for any existing hydrocarbon
derivatives related to the Company's fixed price pre-paid crude oil and pre-paid
natural gas sales. The model also includes the Company's net interests in its
subsidiaries' crude oil and natural gas hydrocarbon derivatives and forward
sales contracts. Based upon the Company's risk model, the value at risk related
to hydrocarbon derivatives held for hedging purposes was approximately $8
million at March 31, 2004. The value at risk related to hydrocarbon derivatives
held for non-hedging purposes was $1 million at March 31, 2004.
In order to provide a more comprehensive view of the Company's commodity price
risk, a tabular presentation of open hydrocarbon derivatives is also provided.
The following table sets forth the future volumes and price ranges of
hydrocarbon derivatives held by the Company at March 31, 2004, along with the
fair values of those instruments.
-39-
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
2004 2005 2006 2007-2008 Fair Value
Asset (Liability) (b)(c)
- -----------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 1,160,000 30,000 - - $ 1,200
Average price, per MMBtu $ 4.86 $ 5.01
Volume (MMBtu) (11,010,000) $ (2,642)
Average price, per MMBtu $ 5.70
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 14,817,500 10,163,000 7,218,000 14,459,000 $ 104,679
Average swap price, per MMBtu $ 3.90 $ 3.14 $ 2.42 $ 2.50
Receive fixed price
Volume (MMBtu) 30,640,000 - - - $ (24,619)
Average swap price, per MMBtu $ 5.27
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) - - - - $ (33)
Average ceiling price, per MMBtu
Average floor price, per MMBtu
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (3,229,000) - - - $ (16,727)
Average price, per Bbl $ 32.52
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 540,000 - - - $ (4,144)
Average ceiling price, per Bbl $ 28.40
Average floor price, per Bbl $ 24.00
===================================================================================================================================
(a) Positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Includes $2,677 thousand in assumed liabilities which were capitalized as acquisition costs.
-40-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
2004 2005 Fair Value
Asset (Liability) (b)
- ------------------------------------------------------------------- --------------- ------------ --------------------------
Natural Gas Futures Positions
Volume (MMBtu) 3,820,000 $ 916
Average price, per MMBtu $ 5.55
Volume (MMBtu) (3,720,000) $ (1,413)
Average price, per MMBtu $ 5.43
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 10,892,500 $ 7,230
Average swap price, per MMBtu $ 5.22
Receive fixed price
Volume (MMBtu) 9,359,463 $ (8,835)
Average swap price, per MMBtu $ 5.08
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Swap Positions
Volume (MMBtu) 27,880,000 $ 986
Average price paid, per MMBtu $ 0.30
Volume (MMBtu) 29,105,000 $ (802)
Average price received, per MMBtu $ 0.31
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed & OTC)
Call Volume (MMBtu) 1,120,000 $ 20
Average Call price $ 5.99
Call Volume (MMBtu) (7,340,000) $ (98)
Average Call price $ 6.09
Put Volume (MMBtu) 4,180,000 $ (1,188)
Average Put Price $ 4.16
Put Volume (MMBtu) (6,920,000) $ 1,519
Average Put Price $ 4.39
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 4,480,000 $ 13,687
Average price, per Bbl $ 32.79
Volume (Bbls) (4,830,000) $(12,345)
Average price, per Bbl $ 32.89
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Listed & OTC)
Call Volumes (Bbls) 200,000 $ (148)
Average price, per Bbl $ 40.00
Call Volumes (Bbls) (600,000) $ 287
Average price, per Bbl $ 39.92
Put Volume (Bbls) 100,000 $ (158)
Average price, per Bbl $ 33.00
Put Volume (Bbls) (640,000) $ 718
Average price, per Bbl $ 22.03
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 7,428,440 654,560 $ 21,986
Average swap price, per Bbl $ 30.47 26.91
Receive fixed price
Volume (Bbls) 6,361,960 754,540 $(21,810)
Average swap price, per Bbl $ 30.24 26.11
===========================================================================================================================
(a) Positions reflect long (short) volumes.
(b) Includes $1,866 thousand net claims against counterparties with non-investment grade credit ratings.
-41-
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, the Company's management,
with the participation of the Chief Executive Officer and Chief Financial
Officer, carried out an evaluation of the effectiveness of the design and
operation of the Company's disclosure controls and procedures pursuant to Rule
13a-15(b) of the Securities Exchange Act of 1934. Based upon that evaluation,
the Chief Executive Officer and Chief Financial Officer concluded, as of that
time, that the Company's disclosure controls and procedures are effective in
timely identifying material information potentially required to be included in
the Company's SEC filings.
There was no change in the Company's internal controls over financial reporting
that occurred during the first quarter of 2004 that has materially affected, or
is reasonably likely to materially affect, the Company's internal control over
financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 will require the Company to
include an internal control report with its 2004 annual report on Form 10-K. The
internal control report must assert, among other things, (i) management's
responsibilities to establish and maintain adequate internal control over
financial reporting and (ii) management's assessment of the effectiveness of
this internal control as of the end of the most recent fiscal year. The
Company's independent auditors will, in 2004, be required to audit, and report
on, these assertions. In order to achieve compliance with Section 404 within the
statutory period, management has formed a steering committee and adopted a
detailed project work plan to assess the adequacy of the Company's internal
controls, remediate any control weaknesses that may be identified and validate
through testing that controls are functioning as documented. The Company may
make changes in its internal control processes from time to time.
-42-
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
See the information with respect to certain legal proceedings pending or
threatened against the Company previously reported in Item 3 of Unocal's Annual
Report on Form 10-K for the year ended December 31, 2003, as amended. There is
incorporated by reference: the information regarding the environmental
remediation reserve and possible additional remediation costs in notes 14 and 15
to the consolidated financial statements in Item 1 of Part I of this report; the
discussion of such amounts in the Environmental Matters section of Management's
Discussion and Analysis in Item 2 of Part I; and the information regarding
certain litigation and claims, tax matters and other contingent liabilities in
note 15 to the consolidated financial statements.
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES.
The following table shows information regarding repurchases by the Company of
its shares of common stock during the first quarter of 2004:
- ----------------------------------------------------------------------------------------------------------------------------
Total Number of
Shares
Total Purchased as
Number of Part of Publicly Maximum Dollar Value of
Shares Average Announced Shares That May Yet Be
Purchased Price Paid Plans or Purchased Under the
Period (1) per share Programs Plans or Progrmas (2)
- ----------------------------------------------------------------------------------------------------------------------------
January 1 through January 31, 2004 63,622 $37.62 None $189,000,000
- ----------------------------------------------------------------------------------------------------------------------------
February 1 through February 29, 2004 567,219 $36.88 None $189,000,000
- ----------------------------------------------------------------------------------------------------------------------------
March 1 through March 31, 2004 36,804 $37.65 None $189,000,000
- ----------------------------------------------------------------------------------------------------------------------------
Total 667,645 $36.99 None $189,000,000
- ----------------------------------------------------------------------------------------------------------------------------
1. During the quarter, 48,169 shares repurchased were restricted stock
cancelled by the Company for the payment of withholding taxes due on
restricted stock that vested under various employee restricted stock
plans.
During the quarter, 80,268 shares were also purchased in the open
market and distributed to employee participants in the Company's
savings plans, which are defined contribution plans with 401(k)
features.
The Company repurchased 539,208 shares from four of the original
participants of its Executive Stock Purchase Program of 2000 at market
price. The purchase of this number of shares was separately approved by
the Board of Directors in February 2004.
2. In December 1996, the Board of Directors authorized the repurchase of
$400 million of its common stock. In January 1998, the Board extended
the stock repurchase program, increasing the authorized amount by $200
million. There is no expiration date to the repurchase program. A
balance of $189 million remains for additional purchases.
-43-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 45 of this report lists the
exhibits that are filed or furnished, as applicable, as part of this
report.
(b) Reports on Form 8-K filed or furnished during the first quarter of
2004:
(1) Current Report on Form 8-K, dated January 13, 2004, and filed
January 14, 2004, for the purpose of reporting, under Item 5, a
discovery in the deepwater Gulf of Mexico.
(2) Current Report on Form 8-K, dated January 27, 2004, and filed
February 6, 2004, for the purpose of reporting, under Item 5, the
Company's fourth quarter 2003 earnings and related information,
the Company's 2003 reserve replacement and finding development
and acquisitions costs, the Company's 2004 outlook.
(3) Current Report on Form 8-K, dated February 25, 2004, and filed
March 4, 2004, for the purpose of reporting, under Item 5, a
discovery in deepwater Indonesia and the sale of certain
geothermal assets.
(4) Current Report on Form 8-K, dated March 11, 2004, and filed March
15, 2004, for the purpose of reporting, under Item 5, the
Company's agreement to sell certain fee minerals interests.
SIGNATURE
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 thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: May 7, 2004 By: /s/JOE D. CECIL
------------------------------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
-44-
EXHIBIT INDEX
3 Bylaws of Unocal, as amended through March 31, 2004, and currently in
effect.
12.1 Statement regarding computation of ratio of earnings to fixed charges of
Unocal Corporation for the three months ended March 31, 2004 and 2003.
12.2 Statement regarding computation of ratio of earnings to fixed charges of
Union Oil Company of California for the three months ended March 31, 2004
and 2003.
31.1 CEO certifications pursuant to Exchange Act Rule 13a-14(a).
31.2 CFO certifications pursuant to Exchange Act Rule 13a-14(a)
32 Furnished Certifications Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.
-45-