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, 2003
--------------------
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, 2003: 258,024,448
TABLE OF CONTENTS
PAGE
Glossary.................................................................... i
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Earnings............................................. 1
Consolidated Balance Sheet........................................ 2
Consolidated Cash Flows........................................... 3
Notes to Financial Statements..................................... 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations....................... 27
Operating Highlights ............................................... 28
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 6. Exhibits and Reports on Form 8-K.................................... 44
SIGNATURE................................................................... 45
CERTIFICATIONS.............................................................. 46
EXHIBIT INDEX............................................................... 48
GLOSSARY
Below are certain definitions of key terms that may be in use in this Form 10-Q
report.
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
CF Cubic feet Btu British thermal units
BOE Barrels of oil equivalent DD&A Depreciation, depletion
and amortization
Liquids Crude oil, condensate and NGLs NGLs Natural gas liquids
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 A term used to quantify oil and natural gas amounts using the same
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 measure of the amount of heat required
to raise the temperature of one pound of water one degree Fahrenheit.
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 that the Company is entitled to. 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 desires to drill on the leased acreage. The assignor
usually retains a royalty or reversionary interest in the lease. The
interest received by an assignee is a "farm-in," while the interest
transferred by the assignor is a "farm-out."
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.
o Gross acres or gross wells are the total acres or wells in which a working
interest is owned.
i
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 that are 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 pressure 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 Production Sharing Contract ("PSC") is a contractual agreement between the
Company and a host government whereby the Company, acting as contractor,
bears all exploration costs, 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
such 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 that the Company has in a
joint venture, partnership, consortium, project or acreage.
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 2003 2002
----------------------------------------------------------------------------
Revenues
Sales and operating revenues $ 1,775 $ 1,035
Interest, dividends and miscellaneous income 11 12
Gain on sales of assets 3 2
----------------------------------------------------------------------------
Total revenues 1,789 1,049
Costs and other deductions
Crude oil, natural gas and product purchases 646 295
Operating expense 294 299
Administrative and general expense 51 43
Depreciation, depletion and amortization 260 224
Asset impairments - -
Dry hole costs 71 28
Exploration expense 55 59
Interest expense 38 51
Property and other operating taxes 22 16
Distributions on convertible preferred
securities of subsidiary trust 8 8
----------------------------------------------------------------------------
Total costs and other deductions 1,445 1,023
Earnings from equity investments 43 37
----------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 387 63
----------------------------------------------------------------------------
Income taxes 168 40
Minority interests 2 1
----------------------------------------------------------------------------
Earnings from continuing operations 217 22
----------------------------------------------------------------------------
Earnings from discontinued operations - -
Cumulative effects of accounting changes (a) (83) -
----------------------------------------------------------------------------
Net earnings $ 134 $ 22
============================================================================
Basic earnings per share of common stock (b)
Continuing operations $ 0.84 $ 0.09
Net earnings $ 0.52 $ 0.09
Diluted earnings per share of common stock (c)
Continuing operations $ 0.82 $ 0.09
Net earnings $ 0.52 $ 0.09
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) 258,005 244,207
(c) Diluted weighted average shares
outstanding (in thousands) 271,729 245,247
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At March 31, At December 31,
-------------------------------------------
Millions of dollars 2003 (a) 2002
---------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 356 $ 168
Accounts and notes receivable - net 1,116 994
Inventories 91 97
Deferred income taxes 120 90
Other current assets 27 26
---------------------------------------------------------------------------------------------------------------------
Total current assets 1,710 1,375
Investments and long-term receivables - net 1,038 1,044
Properties - net (b) 8,114 7,879
Goodwill 125 122
Deferred income taxes 231 210
Other assets 150 130
---------------------------------------------------------------------------------------------------------------------
Total assets $ 11,368 $ 10,760
=====================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,110 $ 1,024
Taxes payable 346 223
Dividends payable 51 51
Interest payable 52 50
Current portion of environmental liabilities 131 113
Current portion of long-term debt and capital leases 6 6
Other current liabilities 173 165
---------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,869 1,632
Long-term debt and capital leases 2,918 3,002
Deferred income taxes 631 593
Accrued abandonment, restoration and environmental liabilities 878 622
Other deferred credits and liabilities 846 816
Minority interests 275 275
Commitments and contingencies - Note 13
Company-obligated mandatorily redeemable convertible preferred
securities of a subsidiary trust holding solely parent debentures 522 522
Common stock ($1 par value, shares authorized: 750,000,000 (c)) 269 269
Capital in excess of par value 963 962
Unearned portion of restricted stock issued (17) (20)
Retained earnings 3,103 3,021
Accumulated other comprehensive income (443) (486)
Notes receivable - key employees (35) (37)
Treasury stock - at cost (d) (411) (411)
---------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 3,429 3,298
---------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 11,368 $ 10,760
=====================================================================================================================
(a) Unaudited
(b) Net of accumulated depreciation, depletion and amortization of: $ 12,538 $ 12,277
(c) Number of shares outstanding (in thousands) 258,005 257,980
(d) Number of shares (in thousands) 10,623 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 2003 2002
---------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 134 $ 22
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 260 224
Asset impairments - -
Dry hole costs 71 28
Amortization of exploratory leasehold costs 24 22
Deferred income taxes 30 (23)
Gain on sales of assets (pre-tax) (3) (2)
Cumulative effects of accounting changes 83 -
Other 32 (11)
Working capital and other changes related to operations
Accounts and notes receivable (122) (14)
Inventories 6 6
Accounts payable 86 (51)
Taxes payable 123 82
Other (39) (12)
---------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 685 271
---------------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (429) (390)
Proceeds from sales of assets 66 28
Proceeds from sale of discontinued operations - 2
---------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (363) (360)
---------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Long-term borrowings 16 399
Reduction of long-term debt and capital lease obligations (100) (123)
Minority interests (2) (2)
Proceeds from issuance of common stock 1 14
Dividends paid on common stock (52) (49)
Other 3 (2)
---------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (134) 237
---------------------------------------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents 188 148
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Cash and cash equivalents at beginning of year 168 190
---------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 356 $ 338
===========================================================================================================================
Supplemental disclosure of cash flow information: Cash paid during the period
for:
Interest (net of amount capitalized) $ 35 $ 53
Income taxes (net of refunds) $ 23 $ (8)
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 2002 Annual Report on Form 10-K.
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. Investments in entities
without a controlling interest are accounted for by the equity method or cost
basis. 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, 2003, are not necessarily
indicative of future financial results.
Certain items in the prior year financial statements have been reclassified to
conform to the 2003 presentation.
2. Accounting Changes
SFAS No. 143: Effective January 1, 2003, the Company adopted Statement of
Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations." If a reasonable estimate of fair value can be made,
this Statement requires that the Company recognize liabilities related to the
legal obligations associated with the retirement of its tangible long-lived
assets in the periods in which the obligations are incurred (typically when the
assets are installed). These obligations include the required decommissioning
and removal of certain oil and gas platforms, plugging and abandonment of oil
and gas wells and facilities and the closure and site restoration of certain
mining facilities. The recognized liability amounts are based upon future
retirement cost estimates and incorporate many assumptions such as expected
economic recoveries of crude oil and natural gas, time to abandonment, future
inflation rates and the risk free rate of interest adjusted for the Company's
credit costs.
The Company has interests in some long-lived assets, such as commercial natural
gas storage facilities, commercial crude oil and products storage facilities,
commercial pipelines, etc. where the operations are not tied to any particular
operating field reserves. As the Company expects these assets to continue
operations for the foreseeable future, it cannot reasonably estimate when, or
if, these facilities will be abandoned. Accordingly, the Company has not accrued
abandonment and restoration liabilities for these assets. The Company will
continue to monitor these assets for any changes to this position.
Prior to January 1, 2003, the Company was required under SFAS No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies" to accrue its
abandonment and restoration costs ratably over the productive lives of its
assets. The Company previously used the units-of-production method to accrue
these costs. SFAS No. 19 resulted in higher costs being accrued early in the
fields' lives when production was at its highest levels and abandonment and
restoration costs accruals were matched with the revenues as oil and gas were
produced.
-4-
Under SFAS No. 143, when the liabilities for asset retirement obligations are
initially recorded at their fair value, capital costs of the related assets will
be increased by equal corresponding amounts. Over time, changes in the present
value of the liabilities will be accreted and expensed and the capitalized asset
costs will be depreciated over the useful lives of the corresponding assets.
Because SFAS No. 143 requires the use of interest accretion for revaluing asset
retirement obligation liabilities as a result of the passage of time, associated
accretion costs will be higher near the end of the fields' lives when oil and
gas production and related revenues are at their lowest levels.
Accounting Principles Board ("APB") Opinion No. 20, "Accounting Changes"
requires that the Company calculate the retroactive impact of adopting SFAS No.
143 from the inception of its asset retirement obligations to its January 1,
2003 adoption date. APB No. 20 requires that this impact be quantified and
reported as a cumulative effect of an accounting change on the earnings
statement. This cumulative effect includes the catch up of SFAS No. 143
accretion expense related to the fair value of the liabilities as well as the
catch up of associated depreciation expense related to the increased capital
costs of the corresponding assets. The cumulative effect also includes the
reversal of abandonment and restoration costs previously charged to earnings
under SFAS No. 19. In addition to the impact on earnings due to the differences
in applying SFAS No. 19 and SFAS No. 143 to the Company's oil and gas
operations, the cumulative effect also includes the impact related to the
Company's mining operations under SFAS No. 143.
In the first quarter of 2003, the Company recognized a one time after-tax charge
of $83 million as the cumulative effect of an accounting change related to the
adoption of SFAS No. 143. The Company also increased its accrued abandonment and
restoration liabilities by $268 million and increased its net properties by $138
million on the consolidated balance sheet as a result of the adoption of SFAS
143 as of January 1, 2003.
At January 1, 2003 and March 31, 2003, the Company had accrued a total of $758
million and $762 million, respectively, in estimated abandonment and restoration
costs. First quarter 2003 accretion expense of approximately $11 million pre-tax
was partially offset by abandonment liability settlements completed during the
period. There were no material abandonment and restoration liabilities incurred
or revisions in abandonment and restoration cost estimates during the first
quarter 2003. The March 31, 2003 liability amount represents approximately
one-half of the Company's determinable abandonment and restoration costs,
adjusted for inflation.
The Company estimates that the impact of adopting SFAS No. 143 on its 2003
operating earnings will be an incremental charge of approximately $9 million
after tax.
Had the Company been required to adopt SFAS No. 143 on January 1, 2002, the
estimated liability for abandonment and restoration costs using current
assumptions would have been approximately $713 million and $723 million at
January 1, 2002 and March 31, 2002 respectively. Pro-forma net income
information for the period ended March 31, 2002 is as follows:
As Pro-
Millions of dollars except per share amounts Reported Forma
-------------------------------------------- ------------ -------------
Net Income $22 $20
Earnings per Share:
Basic $0.09 $0.08
Diluted $0.09 $0.08
SFAS No. 146: Effective January 1, 2003, the Company adopted SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities." This
Statement provides guidance on the recognition and measurement of liabilities
associated with disposal activities. The adoption of the Statement did not have
a material effect on the Company's financial position or results of operations.
-5-
SFAS No. 148: Effective January 1, 2003, the Company adopted SFAS No. 148,
"Accounting for Stock-Based Compensation--Transition and Disclosure--an
amendment of FASB Statement No. 123." The statement provides for three methods
of transitioning from the intrinsic value to the fair value method of accounting
for stock-based compensation. This Statement also amended the disclosure
requirements of SFAS No. 123 and APB Opinion No. 28, "Interim Financial
Reporting," to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. The
disclosure requirements of the Statement were adopted in the Company's 2002
Annual Report on Form 10-K. The Company adopted the fair value recognition
provisions of SFAS No. 148, on a prospective basis, effective January 1, 2003
(see note 7 for further details). This change is estimated to decrease 2003
after-tax income by approximately $5 million. When fully phased in for future
grants over the next three years, the annual expense is estimated to be
approximately $10 million after-tax. Adoption of the fair value recognition
provisions will not have a material effect on the Company's 2003 financial
position or results of operations.
FASB Interpretation No. 45: Effective January 1, 2003, the Company adopted FASB
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others." This
Interpretation requires the recognition of certain guarantees as liabilities at
fair market value and is effective for guarantees issued or modified after
December 31, 2002. The Company has included the disclosure requirements of the
Interpretation in note 13. The adoption of this Interpretation did not have a
material effect on the Company's financial position or results of operations.
FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities." This
Interpretation requires the consolidation of certain companies that are defined
as variable interest entities. This Interpretation is effective for new variable
interest entities as of February 1, 2003. The effective date for the
consolidation of entities existing prior to February 1, 2003 is July 1, 2003.
The Company has included the disclosure requirements of the Interpretation in
this report and expects the adoption of the recognition (i.e., consolidation)
requirements of the Interpretation to increase its consolidated long-term debt
by approximately $320 million in the third quarter of 2003. This amount will
include $242 million related to a partnership interest in which the Company
currently has a minority interest liability (see note 11 for further details)
and $78 million of third-party debt related to Dayabumi Salak Pratma, Ltd.
("DSPL"), an equity investee that sells electricity generated from geothermal
steam in Indonesia (see note 11 for further details).
3. Other Financial Information
During the first quarters of 2003 and 2002, approximately 25 percent and 20
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 purchase category on the consolidated
earnings statement.
Capitalized interest totaled $16 million and $9 million for the first quarters
of 2003 and 2002, respectively.
Exploration expense on the consolidated earnings statement consisted of the
following:
For the Three Months
Ended March 31,
---------------------------
Millions of dollars 2003 2002
--------------------------------------------------------------------------------
Exploration operations $ 15 $ 23
Geological and geophysical 14 11
Amortization of exploratory leases 24 22
Leasehold rentals 2 3
--------------------------------------------------------------------------------
Exploration expense $ 55 $ 59
================================================================================
-6-
4. Restructuring
In 2002, the Company's Gulf Region business unit, which is part of the U.S.
Lower 48 operations in the Exploration and Production segment, adopted a
restructuring plan that resulted in the accrual of a $19 million pre-tax
restructuring charge. The charge included the estimated costs of terminating 202
employees, all of whom were terminated in 2002. At March 31, 2003, approximately
$14 million of the restructuring costs had been paid and charged against the
liability, leaving accrued costs of $5 million on the consolidated balance sheet
at March 31, 2003. The remaining costs are expected to be paid by the end of
2003.
Also in 2002, the Company adopted a restructuring plan that resulted in the
accrual of a $4 million pre-tax restructuring charge related to Exploration and
Production operations in Alaska. The restructuring charge reflected the costs of
terminating 46 employees, of whom 38 had been terminated, as of March 31, 2003.
Approximately $1 million of the restructuring costs had been paid and charged
against the liability, leaving accrued costs of $3 million on the consolidated
balance sheet at March 31, 2003. The remaining costs are expected to be paid
during 2003 and the first half of 2004.
5. Income Taxes
Income taxes on earnings from continuing operations for the first quarter of
2003 were $168 million compared with $40 million first quarter of 2002. The
effective income tax rate for the first quarter of 2003 was 43 percent compared
with 63 percent for the first quarter of 2002. The lower effective tax rate in
2003, as compared with 2002, reflects the mix of positive domestic and foreign
earnings in 2003 compared to the mix of domestic losses and foreign earnings in
2002. Foreign earnings are generally taxed at higher rates.
6. 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 three months ended March 31, 2003 and 2002:
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
----------------------------------------------------------------------------------------------------------------------------
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
============
Three months ended March 31, 2002
Earnings from continuing operations $ 22 244.2
Basic EPS $ 0.09
============
Effect of dilutive securities
Options and common stock equivalents 1.0
--------------------------------
Diluted EPS 22 245.2 $ 0.09
============
Distributions on subsidiary trust preferred securities (after-tax) 7 12.3
--------------------------------
Antidilutive $ 29 257.5 $ 0.11
----------------------------------------------------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the three months ended March
31, 2003 and 2002, were options outstanding to purchase approximately 11 million
and 5.1 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.
-7-
7. Stock-Based Compensation
Prior to 2003, the Company applied APB Opinion No. 25, "Accounting for Stock
Issued to Employees", and related interpretations in accounting for stock-based
compensation. Before 2003, 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 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 2003 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:
For the Three Months
Ended March 31,
------------------------
Millions of dollars except per share amounts 2003 2002
--------------------------------------------------------------------------------
Net earnings
As reported $ 134 $ 22
Add: Stock-based employee compensation expense
included in reported net income,
net of related tax effects
and minority interests 2 7
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 (4) (12)
------------------------
Pro forma net earnings $ 132 $ 17
========================
Net earnings per share:
Basic - as reported $ 0.52 $ 0.09
Basic - pro forma $ 0.51 $ 0.07
Diluted - as reported $ 0.52 $ 0.09
Diluted - pro forma $ 0.51 $ 0.07
8. Comprehensive Income
The Company's comprehensive income was:
For the Three Months
Ended March 31,
-----------------------
Millions of dollars 2003 2002
--------------------------------------------------------------------------------
Net earnings $ 134 $ 22
Change in unrealized loss
on hedging instruments (a) (10) (20)
Reclassification adjustment for settled
hedging contracts (b) 7 6
Unrealized foreign currency translation adjustments 46 (3)
--------------------------------------------------------------------------------
Total comprehensive income $ 177 $ 5
================================================================================
(a) Net of tax effect of: (6) (12)
(b) Net of tax effect of: 4 3
-8-
9. Cash and Cash Equivalents
At March 31, At December 31,
----------------------------------------
Millions of dollars 2003 2002
--------------------------------------------------------------------------------
Cash $ 157 $ 58
Time deposits 131 110
Restricted cash 1 -
Marketable securities 67 -
--------------------------------------------------------------------------------
Cash and cash equivalents $ 356 $ 168
================================================================================
The marketable securities at March 31, 2003 reflect the Company's short-term
investment in a money market fund which invests in U.S. Treasury and other U.S.
government agency obligations plus high quality bonds and commercial paper
obligations of domestic corporations. The fund is rated "AAA" by Moody's
Investors Service, Inc. and Standard & Poor's Ratings Services.
10. Long Term Debt and Credit Agreements
During the first three months of 2003, the Company's consolidated debt,
including the current portion, decreased by $84 million. The Company retired $89
million in 9.25% debentures which matured during the first quarter and paid down
$10 million of medium-term notes which matured during the quarter. These
decreases were partially offset by a $15 million increase in the Company's
3-year $295 million Canadian dollar-denominated non-revolving credit facility.
At March 31, 2003, the borrowings under the credit facility translated to $201
million, using applicable foreign exchange rates.
11. Variable Interest Entities
In 1999, the Company contributed fixed-price overriding royalty interests from
its working interest shares in certain oil and gas producing properties in the
Gulf of Mexico to Spirit Energy 76 Development, L.P. ("Spirit LP"), a limited
partnership. In exchange for its overriding royalty contributions, valued at
$304 million, the Company received an initial general partnership interest in
Spirit LP of approximately 55 percent. An unaffiliated investor contributed $250
million in cash to the partnership in exchange for an initial limited
partnership interest of approximately 45 percent. The Company consolidates this
partnership. The fixed-price overrides are subject to economic limitations of
production from the affected fields. The limited partner is entitled to receive
a priority allocation of profits and cash distributions. The limited partner's
share has a maximum term of 20 years, but may terminate in 2005 under certain
conditions. If the Company's credit rating falls below Ba1 or BB+, then the
priority return to the limited partner increases by two percent and the Company
would have to provide cash collateral or a letter of credit for the $250
million. Almost all the minority interests in earnings are paid out to the
limited partner as cash distributions. The minority interest on the Company's
consolidated balance sheet related to this transaction was approximately $252
million at March 31, 2003. The primary purpose of this transaction was to raise
capital. In the third quarter of 2003, FASB Interpretation No. 46 will require
that the Company consolidate the unaffiliated investor (see note 2). This is
expected to result in a reclassification of $242 million from minority interests
to long-term debt on the Company's consolidated balance sheet. At March 31,
2003, the Company's maximum exposure to loss as a result of its involvement with
Spirit Energy 76 Development, L.P. was approximately $251 million.
DSPL is a special purpose company formed for the purpose of building and
operating a geothermal energy fueled power generating facility in Indonesia.
Under a long-term electricity sales contract, this entity provides power to the
Indonesian state-owned electricity company, PT. PLN (Persero) ("PLN"). Unocal
Geothermal of Indonesia, Ltd. ("UGI") owns a 50 percent interest in DSPL and is
under contract to administer DSPL operations. DSPL has no employees of its own.
DSPL had loans and notes payable totaling $85 million at March 31, 2003. DSPL's
debt obligations are non-recourse to UGI and to the Company, as neither entity
has guaranteed these obligations. Effective in the third quarter of 2003, FASB
Interpretation No. 46 (see note 2 for further details), will require the Company
to consolidate DSPL, resulting in the reporting of the $78 million as long-term
debt on the consolidated balance sheet at that time. At March 31, 2003, the
Company's maximum exposure to loss as a result of its involvement with DSPL was
approximately $100 million.
-9-
12. Accrued Abandonment, Restoration and Environmental Liabilities
Effective January 1, 2003, the Company adopted SFAS No. 143 which increased its
accrued abandonment and restoration liabilities by $268 million (see note 2). At
March 31, 2003, the Company had accrued $762 million in estimated abandonment
and restoration costs as liabilities. This amount represented approximately
one-half of the Company's determinable abandonment and restoration costs,
adjusted for inflation. Accretion expense for the first quarter was
approximately $11 million pre-tax (see note 2). There were no material
abandonment and restoration liabilities incurred or settled during the first
quarter.
The Company's reserve for environmental remediation obligations at March 31,
2003 totaled $249 million, of which $131 million was included in current
liabilities. This compared with $245 million at December 31, 2002, of which $113
million was included in current liabilities.
13. 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.
As disclosed in note 12, at March 31, 2003, the Company had accrued $249 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
-10-
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.
The accrued costs and the possible additional costs are shown below for four
categories of sites:
At March 31, 2003
----------------------------
Possible
Additional
Millions of dollars Reserve Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 17 $ 10
Active Company facilities 34 25
Company facilities sold with retained liabilities
and former Company-operated sites 102 80
Inactive or closed Company facilities 96 100
--------------------------------------------------------------------------------
Total $ 249 $ 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.
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
-11-
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, 2003, Unocal had received notifications from the U.S. Environmental
Protection Agency ("EPA") that the Company may be a PRP at 22 sites and may
share certain liabilities at these sites. Of the total, two 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.
Of the remaining 19 sites, where the Company has concluded that liability is
probable and to the extent costs can be reasonably estimated, a reserve of $13
million has been established for future remediation and settlement costs.
Various state agencies and private parties had identified 18 other similar PRP
sites. Two 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 two 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 13
sites, a reserve of $4 million has been established for future remediation and
settlement costs.
The sites discussed above exclude 121 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
The Company has a reserve of $34 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 made payments of $4 million for this category of sites in the first
quarter of 2003.
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.
-12-
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 $102 million for this group of sites.
Payments of $4 million were made during the first three months of 2003 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 $96 million has been established for these types of facilities. In
the first quarter of 2003, provisions of $11 million were recorded for the
"Inactive or closed Company facilities" category of sites, primarily for
remediation projects at the Company's former refinery in Beaumont, Texas. The
Company has been working with the Texas Commission on Environmental Quality
(TCEQ) to develop plans for closing impoundments used in the site's former
operations and for other remediation projects. In the first quarter, the Company
recorded a provision for the revised estimated costs of the impoundment closure
plan based on the TCEQ initial draft permit that was issued in the first
quarter. In the first quarter of 2003, $3 million in payments were made 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 assurance for anticipated costs of
remediation activities at its inactive Guadalupe oil field. Also, pursuant to a
1995 settlement agreement between Molycorp and the California Department of
Toxic Substances Control (and subsequent final judgment entered by the Superior
Court), the Company must provide financial assurance for anticipated costs of
disposing of certain wastes, as well as closing facilities associated with the
handling of those wastes, at Molycorp's Mountain Pass, California, facility. At
March 31, 2003, amounts in the remediation reserve for these facilities totaled
$101 million, as included in the previously discussed "Active Company
Facilities" and "Inactive or closed Company facilities" categories. 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 $70 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
-13-
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
City of Santa Monica MTBE Lawsuit: In 2000, the City of Santa Monica, California
(the "City") sued Shell Oil Company and other oil companies, including the
Company, for contamination with methyl tertiary butyl ether ("MTBE") and a
related chemical, tertiary butyl alcohol ("TBA"), of water pumped from the
City's Charnock wellfield (City of Santa Monica v. Shell Oil Company et al.
California Superior Court, Orange County, Case No. 01CC04331). The City alleges
that releases from sites owned by Shell, ChevronTexaco Corporation and
ExxonMobil Corporation caused the wellfield to be shut down, and that releases
from sites owned by Unocal subsequently impacted the wellfield. In 2001, Shell
filed a cross-complaint against the Company and other oil companies, seeking the
recovery of the funds it has expended to respond to the contamination. Further
proceedings on this cross-complaint remain stayed.
In November 2002, the City, ChevronTexaco and ExxonMobil entered into a
settlement (the "Chevron-Exxon Settlement"), subject to court approval, under
which the two companies would pay the City $30 million and construct and operate
a water treatment plant. The City's expert has estimated that the cost of
treatment plant construction and operation could exceed $500 million, but other
experts estimate the cost of aquifer restoration at $33 million. The Company,
Tosco Corporation (now part of Conoco Phillips) and other defendants, but not
the Shell defendants, had been invited to participate in this settlement on
terms which would have involved the Company paying the City $7.5 million and
contributing to the costs of the treatment plant. Neither the Company nor the
other invited defendants elected to participate on these terms and in March
2003, the Company, BP (named in the suit as "ARCO") and Ultramar filed a joint
opposition to the Chevron-Exxon Settlement.
The court held a hearing on March 24, 2003 to consider approval of the
settlement and its value as a credit against future recoveries from non-settling
parties, which the settling parties have proposed at $40 million. The court took
the matter under submission but expressed concern that the provision allowing
ChevronTexaco and ExxonMobil to "veto" a settlement by other parties was
improper. ARCO has announced that it settled with the City for $9,750,000 and
has withdrawn its objections to the Chevron-Exxon settlement. Unocal and
Ultramar were offered settlements at the same amount as ARCO. Unocal has
rejected that offer but is seeking good faith negotiations with the City. The
City has agreed, but no date for such negotiations has been set.
Based on a rigorous technical analysis of the data, the Company believes it has
strong defenses to the allegations in the complaint, including the lack of
evidence that its former service stations or activities are responsible for any
contamination that has reached or threatens the wellfield. The Company also
believes it has certain available defenses that the settling defendants and
others may not have due to tolling agreements they entered into with the City;
and, unlike the Shell defendants and the settling defendants, the Company is
neither the object of punitive damages claims nor a cause of the wellfield's
being originally shut down. The Company is also subject to potential partial
responsibility for MTBE or TBA contamination in the wellfield arising from
certain operations in the area of the Company's former gasoline marketing
business that was sold in 1997, and is subject to potential liability, under a
products liability theory, for gasoline it manufactured or sold that was
ultimately distributed to area facilities operated by others. The Company's
current analysis does not indicate any such liabilities are likely to be
significant.
-14-
For several years prior to the City's suit, the EPA and the California Regional
Water Quality Control Board have asserted jurisdiction over contamination of
groundwater potentially affecting the wellfield, and these agencies have issued
a number of orders under RCRA and state law to the Shell defendants and the
other defendant oil companies, including the Company, with respect to both
investigation of individual facilities and regional contamination, and requiring
replacement of water lost to the City, which Shell is currently providing. In
January 2003, the EPA Regional Administrator for Region IX wrote to the settling
parties advising that it intended to issue a unilateral order to all parties
whose releases have been demonstrated to contribute to contamination in the
Charnock Sub-Basin ordering cleanup of MTBE and TBA "hot spots", unless a
settlement in principle among all concerned parties is reached by March 31,
2003. The EPA also intends to defer to the City of Santa Monica's request to
select and implement a wellhead treatment system. The Company received a copy of
this letter. The Company has submitted to these agencies several technical
analyses, which it believes demonstrate that its sites are not a part of any
regional contamination problem, but, rather, present, at the most, localized
issues which the Company, under agency oversight, has been successfully
resolving.
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.
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. Agrium also seeks
declaratory relief concerning the base price of gas under the GPSA, as well as
for the calculation of payments under a "Retained Earnout" covenant 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 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.
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 agreement for the sale of the plant (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.
-15-
The Company believes that certain portions of its disputes with Agrium are
subject to binding arbitration under the terms of the GPSA. The Company
initiated the Arbitration to determine the amount and delivery rate of the
remaining gas supply available under that agreement. Agrium claims the dispute
resolution provisions of the PSA supersede the arbitration provisions of the
GPSA.
In January 2003, the state court ordered that the arbitration issues should be
combined in the litigation but the scope of the court's order is unclear. Agrium
has filed a motion to clarify the order with respect to the Arbitration. The
Company is appealing the order and has filed a motion to stay discovery pending
resolution of that appeal. The parties have agreed in principle to postpone the
Arbitration, pending resolution of the appeal. Discovery is now proceeding.
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 contractors' 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,
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) of entitlement to the recovery of costs incurred
in 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 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.
Nuevo Energy Claim: In March 2003, the Company received a letter from Nuevo
Energy Company regarding a contingent payment for the year 2002 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. Notwithstanding that Nuevo had notified the Company in
January 2003 of its estimate of the payment for 2002, Nuevo now claims that the
long-standing calculation methodology for this payment was incorrect, that no
payment should be due for 2002, and that the payment made for 2001 should be
refunded. The Company disputes Nuevo's new position and expects to commence
litigation in the event that the 2002 payment is not received. The potential
cash exposure to the Company is $27 million.
In view of the inherent difficulty of predicting the outcome of legal matters,
the Company cannot state with confidence what the eventual outcome of the four
preceding matters will be. However, based on current knowledge, none of the
preceding matters is presently expected to have a material adverse effect on the
Company's consolidated financial condition or liquidity, but each of them could
have a material adverse effect on the Company's results of operations for the
accounting period or periods in which one or more of them might be resolved
adversely.
-16-
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 impact not only the year in which the items
arose, but also the Company's tax situation in other tax years. With respect to
1979-1984 taxable years, all issues raised for these years have now been
settled, with the exception of the effect of the carryback of a 1993 net
operating loss ("NOL") to tax year 1984 and resultant credit adjustments. The
1985-1990 taxable years are before the Appeals division of the Internal Revenue
Service. All issues raised with respect to those years have now been settled,
with the exception of the effect of the 1993 NOL carryback and resultant
adjustments. The Joint Committee on Taxation of the U.S. Congress has reviewed
the settled issues with respect to 1979-1990 taxable years and no additional
issues have been raised. While all tax issues for the 1979-1990 taxable years
have been agreed and reviewed by the Joint Committee, these taxable years will
remain open due to the 1993 NOL carryback. The 1993 NOL results from certain
specified liability losses, which occurred during 1993, and which resulted in a
tax refund of $73 million. Consequently, these tax years will remain open until
the specified liability loss, which gave rise to the 1993 NOL, is finally
determined by the Internal Revenue Service and is either agreed to with the IRS
or otherwise concluded in the Tax Court proceeding. In 1999, the United States
Tax Court granted Unocal's motion to amend the pleadings in its Tax Court cases
to place the 1993 NOL carryback in issue. The 1991-1994 taxable years are now
before the Appeals division of the Internal Revenue Service. The 1995-1997
taxable years are under examination by the Internal Revenue Service.
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, 2003, the reserve for this
category totaled $102 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 $80 million. See
the discussion elsewhere in this footnote for additional information regarding
this category.
The Company has guaranteed the debt of certain joint ventures accounted for by
the equity method. The majority of this debt matures evenly through the year
2014. The maximum potential amount of future payments the Company could be
required to make is approximately $21 million.
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.
-17-
Financial Assurance for Unocal Obligations
In the normal course of business, the Company has performance obligations which
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, 2003, the
Company had obtained various surety bonds for approximately $220 million. These
surety bonds included a bond for $90 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 approximately $130 million in various other routine
performance bonds held by local, city, state and federal agencies. The Company
also had obtained approximately $33 million in standby letters of credit at
March 31, 2003. The Company has entered into indemnification obligations in
favor of the providers of these surety bonds and letters of credit. In addition,
the Company has various other guarantees for approximately $550 million.
Guarantees for approximately $333 million of this amount 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 $250 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.
Approximately $134 million of the $550 million in guarantees mentioned in the
previous paragraph represents 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.
Other matters
The Company has a lease agreement relating to its Discoverer Spirit deepwater
drillship, with a remaining term of approximately two and a half years at March
31, 2003. The drillship has a current minimum daily rate of approximately
$224,000. The future remaining minimum lease payment obligation was
approximately $200 million at March 31, 2003.
The Company also has other contingent liabilities with respect to litigation,
claims and contractual agreements arising in the ordinary course of business. On
the basis of 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-
14. Financial Instruments and Commodity Hedging
Fair values of debt and other long-term instruments - The estimated fair value
of the Company's long-term debt at March 31, 2003, including the current
portion, was approximately $3,296 million. The fair value was based on the
discounted amounts of future cash outflows using the rates offered to the
Company for debt with similar remaining maturities.
The estimated fair value of Unocal Capital Trust's 6 1/4 % convertible preferred
securities was approximately $506 million at March 31, 2003. The fair value was
based on the closing trading price of the preferred securities on March 31,
2003.
Commodity hedging activities - The Company uses hydrocarbon derivatives to
mitigate its overall exposure to fluctuations in hydrocarbon commodity prices.
During the three months ended March 31, 2003, the amount of the ineffectiveness
for both cash flow and fair value hedges was immaterial. At March 31, 2003, the
Company had approximately $25 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
2003 through October 2004. Of this amount, approximately $20 million in
after-tax losses are expected to be reclassified to the consolidated earnings
statement during the next twelve months.
Foreign currency contracts - At March 31, 2003, the Company had approximately $1
million of after-tax deferred gains in accumulated other comprehensive income on
the consolidated balance sheet related to cash flow hedges for future foreign
currency denominated payment obligations through December 2003. All of this
amount is expected to be reclassified to the consolidated earnings statement
during the next twelve months.
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, 2003, the Company had approximately $24 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.
Credit Risk - Financial instruments that potentially subject the Company to
concentrations of credit risks primarily consist of temporary cash investments
and trade receivables. The Company places its temporary cash investments with
high credit quality financial institutions and, by policy, limits the amount of
credit exposure to any one financial institution. The concentration of trade
receivable credit risk is generally limited due to the Company's customers being
spread across industries in several countries. The Company's management has
established certain credit requirements that its customers must meet before
sales credit is extended. The Company monitors the financial condition of its
customers to help ensure collections and to minimize losses.
-19-
15. Supplemental Condensed Consolidating Financial Information
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiaries Unocal Capital Trust and Union Oil. Such guarantees
are full and unconditional and no subsidiaries of Unocal or Union Oil guarantee
these securities.
The following tables present condensed consolidating financial information for
(a) Unocal (Parent), (b) the Trust, (c) Union Oil (Parent) and (d) 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.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
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 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
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 - 211 - (353) -
Earnings from equity investments - - 3 40 - 43
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 132 - 258 350 (353) 387
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (2) - 31 139 - 168
Minority interests - - - 2 - 2
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 134 - 227 209 (353) 217
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes - - (85) 2 - (83)
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 134 $ - $ 142 $ 211 $ (353) $ 134
=============================================================================================================================
-20-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Three months ended March 31, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 209 $ 992 $ (166) $ 1,035
Interest, dividends and miscellaneous income - 8 7 5 (8) 12
Gain (loss) on sales of assets - - 13 (11) - 2
-----------------------------------------------------------------------------------------------------------------------------
Total revenues - 8 229 986 (174) 1,049
Costs and other deductions
Purchases, operating and other expenses 2 - 227 645 (162) 712
Depreciation, depletion and amortization - - 87 137 - 224
Dry hole costs - - 15 13 - 28
Interest expense 8 - 43 9 (9) 51
Distributions on convertible preferred securities - 8 - - - 8
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 8 372 804 (171) 1,023
Equity in earnings of subsidiaries 32 - 128 - (160) -
Earnings from equity investments - - - 37 - 37
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 22 - (15) 219 (163) 63
-----------------------------------------------------------------------------------------------------------------------------
Income taxes (2) - (47) 89 - 40
Minority interests - - - 2 (1) 1
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 24 - 32 128 (162) 22
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes - - - - - -
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 24 $ - $ 32 $ 128 $ (162) $ 22
=============================================================================================================================
-21-
CONDENSED CONSOLIDATED BALANCE SHEET
At March 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 $ - $ - $ 53 $ 303 $ - $ 356
Accounts and notes receivable - net 53 - 263 880 (80) 1,116
Inventories - - 12 79 - 91
Other current assets 1 - 110 36 - 147
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 54 - 438 1,298 (80) 1,710
Investments and long-term receivables - net 4,694 - 4,709 949 (9,314) 1,038
Properties - net - - 2,229 5,885 - 8,114
Other assets including goodwill 3 541 234 514 (786) 506
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,751 $ 541 $ 7,610 $ 8,646 $ (10,180) $ 11,368
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 298 $ 865 $ (53) $ 1,110
Current portion of long-term debt
and capital leases - - - 6 - 6
Other current liabilities 51 3 341 387 (29) 753
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 51 3 639 1,258 (82) 1,869
Long-term debt and capital leases - - 2,321 597 - 2,918
Deferred income taxes - - (145) 776 - 631
Accrued abandonment, restoration
and environmental liabilities - - 437 441 - 878
Other deferred credits and liabilities 541 - 445 636 (776) 846
Minority interests - - - 315 (40) 275
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 4,159 16 3,913 4,623 (9,282) 3,429
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,751 $ 541 $ 7,610 $ 8,646 $ (10,180) $ 11,368
=============================================================================================================================
-22-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ (18) $ 186 $ - $ 168
Accounts and notes receivable - net 54 - 276 738 (74) 994
Inventories - - 10 87 - 97
Other current assets 1 - 85 30 - 116
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 55 - 353 1,041 (74) 1,375
Investments and long-term receivables - net 4,562 - 4,513 960 (8,991) 1,044
Properties - net - - 2,255 5,624 - 7,879
Other assets including goodwill 3 541 272 (12) (342) 462
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,620 $ 541 $ 7,393 $ 7,613 $ (9,407) $ 10,760
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 290 $ 788 $ (54) $ 1,024
Current portion of long-term debt
and capital leases - - - 6 - 6
Other current liabilities 44 3 120 455 (20) 602
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 44 3 410 1,249 (74) 1,632
Long-term debt and capital leases - - 2,418 584 - 3,002
Deferred income taxes - - (116) 709 - 593
Accrued abandonment, restoration
and environmental liabilities - - 320 302 - 622
Other deferred credits and liabilities 541 - 424 184 (333) 816
Minority interests - - - 313 (38) 275
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 4,035 16 3,937 4,272 (8,962) 3,298
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,620 $ 541 $ 7,393 $ 7,613 $ (9,407) $ 10,760
=============================================================================================================================
-23-
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
=============================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
For the Three Months Ended March 31, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 36 $ - $ ( 192) $ 427 $ - $ 271
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - ( 98) (292) - (390)
Proceeds from sales of assets
and discontinued operations - - 3 27 - 30
-----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (95) (265) - (360)
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 376 (100) - 276
Dividends paid on common stock (49) - - - - (49)
Minority interests - - - (2) - (2)
Other 14 - (2) - - 12
-----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (35) - 374) (102) - 237
-----------------------------------------------------------------------------------------------------------------------------
Increase in cash and cash equivalents 1 - 87 60 - 148
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - 62 128 - 190
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ - $ 149 $ 188 $ - $ 338
=============================================================================================================================
-24-
16. Segment Data
The Company's reportable segments are: Exploration and Production, Trade,
Midstream, and Geothermal and Power Operations. General corporate overhead,
unallocated costs and other miscellaneous operations, including real estate,
carbon and minerals and activities relating to businesses that were sold, are
included under the Corporate and Other heading.
Segment Information Exploration & Production Trade
For the Three Months North America International
ended March 31, 2003
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 161 $ 66 $ 58 $ 309 $ 53 $ 920
Other income (loss) (a) 3 - - - - (1)
Inter-segment revenues 388 - 38 91 - -
---------------------------------------------------------------------------------------------------------------------------
Total 552 66 96 400 53 919
Earnings from equity investments 3 - - 9 4 1
Earnings (loss) from continuing operations 111 15 24 121 21 (9)
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes (b) 11 (43) 4 13 - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 122 (28) 28 134 21 (9)
---------------------------------------------------------------------------------------------------------------------------
Assets (at March 31, 2003) 3,333 336 1,243 2,934 868 385
---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (c)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 141 $ 35 $ - $ - $ - $ 32 $ 1,775
Other income (loss) (a) 1 - - 4 - 7 14
Inter-segment revenues 2 - - - - (519) -
---------------------------------------------------------------------------------------------------------------------------
Total 144 35 - 4 - (480) 1,789
Earnings from equity investments 15 1 - - - 10 43
Earnings (loss) from continuing operations 18 12 (23) (31) (17) (25) 217
Earnings from discontinued operations - - - - - - -
Cumulative effects of accounting changes (b) (2) - - - - (66) (83)
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 16 12 (23) (31) (17) (91) 134
---------------------------------------------------------------------------------------------------------------------------
Assets (at March 31, 2003) 538 530 - - - 1,201 11,368
---------------------------------------------------------------------------------------------------------------------------
(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.
-25-
Segment Information Exploration & Production Trade
For the Three Months North America International
ended March 31, 2002
Millions of dollars U.S. Lower 48 Alaska Canada Far East Other
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 114 $ 51 $ 40 $ 230 $ 23 $ 456
Other income (a) 3 - - - - -
Inter-segment revenues 166 - - 52 20 -
---------------------------------------------------------------------------------------------------------------------------
Total 283 51 40 282 43 456
Earnings (loss) from equity investments (1) - - 8 2 (1)
Earnings (loss) from continuing operations 4 (6) (9) 90 12 1
Earnings from discontinued operations - - - - - -
Cumulative effects of accounting changes - - - - - -
--------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 4 (6) (9) 90 12 1
Assets (at December 31, 2002) 3,358 326 1,113 2,861 821 304
--------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Admin Net Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------------------------------------------
Sales & operating revenues $ 62 $ 28 $ - $ - $ - $ 31 $ 1,035
Other income (a) 1 2 - 3 - 5 14
Inter-segment revenues 2 - - - - (240) -
---------------------------------------------------------------------------------------------------------------------------
Total 65 30 - 3 - (204) 1,049
Earnings (loss) from equity investments 19 (3) - - - 13 37
Earnings (loss) from continuing operations 19 6 (24) (37) (23) (11) 22
Earnings from discontinued operations - - - - - - -
Cumulative effects of accounting changes - - - - - - -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) 19 6 (24) (37) (23) (11) 22
Assets (at December 31, 2002) 511 526 - - - 940 10,760
---------------------------------------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) 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 consolidated 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 2002 Annual Report on
Form 10-K.
CONSOLIDATED RESULTS
For the Three Months
Ended March 31,
--------------------------
Millions of dollars 2003 2002
--------------------------------------------------------------------------------
Earnings from continuing operations $ 217 $ 22
Earnings from discontinued operations - -
Cumulative effects of accounting changes (83) -
--------------------------------------------------------------------------------
Net earnings $ 134 $ 22
================================================================================
Continuing Operations
First Quarter Results: Earnings from continuing operations increased by $195
million in the first quarter of 2003 compared to the same quarter a year ago,
primarily reflecting improved results from the Company's exploration and
production operations, due to higher worldwide natural gas and liquids prices.
Higher worldwide commodity prices increased net earnings by approximately $230
million. The Company's worldwide average realized natural gas price, including a
loss of 27 cents per Mcf from hedging activities, was $3.90 per Mcf for the
first quarter of 2003. This was an increase of $1.44 per Mcf, or 59 percent,
from the $2.46 per Mcf, including a benefit of 9 cents per Mcf from hedging
activities, realized during the first quarter of 2002. In the first quarter of
2003, the Company's worldwide average realized liquids price was $29.99 per Bbl,
which was an increase of $11.13 per Bbl, or 59 percent, from the same period a
year ago. The Company's hedging program lowered the average realized liquids
price by 50 cents per Bbl in the first quarter of 2003 while the first quarter
of 2002 included a gain of 6 cents per Bbl from hedging activities. The first
quarter of 2003 included an after-tax gain of $2 million in mark-to-market
accruals and realized gains/losses for non-hedge commodity derivatives recorded
by the Company's Northrock Resources Ltd. ("Northrock") subsidiary, compared to
an after-tax loss of $4 million in the same period a year ago. After-tax
environmental and litigation expenses were $17 million in the first quarter of
2003, compared with $26 million in the same period a year ago.
These positive variance factors were partially offset by higher dry hole costs,
higher DD&A rates (including asset retirement obligation accretion), higher
pension related expenses and lower North America liquids production, which
reduced net earnings by approximately $25 million, $20 million, $10 million and
$10 million, respectively, in the first quarter of 2003 compared with the same
period a year ago. North America liquids production averaged 88,000 Bbl/d in the
first quarter of 2003, down from 99,000 Bbl/d a year ago. Most of the production
decline was due to natural declines in existing fields in the Gulf of Mexico and
the divestiture of various properties in Canada, onshore U.S. and the Gulf of
Mexico.
Cumulative Effects of Accounting Changes
In the first quarter of 2003, the Company recorded a non-cash $83 million
after-tax charge consisting of 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." The
Company also increased its accrued abandonment and restoration liabilities by
$268 million and increased its net properties by $138 million on the
consolidated balance sheet as a result of the adoption of SFAS No.143.
-27-
Revenues
Revenues from continuing operations for the first quarter of 2003 were $1.79
billion compared with $1.05 billion for the same period a year ago. The increase
primarily reflected higher natural gas and liquids prices.
OPERATING HIGHLIGHTS UNOCAL CORPORATION
For the Three Months
Ended March 31,
---------------------------
2003 2002
----------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
U.S. Lower 48 (a) (b) 48 56
Alaska 22 25
Canada 18 18
----------------------------------------------------------------------------
Total liquids 88 99
Natural gas - dry basis (million cubic feet)
U.S. Lower 48 (a) (b) 700 746
Alaska 61 101
Canada 97 90
----------------------------------------------------------------------------
Total natural gas 858 937
North America Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel)
U.S. Lower 48 $30.53 $18.36
Alaska $33.48 $18.61
Canada $28.44 $16.52
Average $30.77 $18.06
Natural gas (per mcf)
U.S. Lower 48 $ 6.29 $ 2.23
Alaska $ 1.20 $ 1.57
Canada $ 5.64 $ 2.34
Average $ 5.83 $ 2.16
----------------------------------------------------------------------------
North America Average Prices (including hedging activities) (c) (d)
Liquids (per barrel)
U.S. Lower 48 $28.97 $18.54
Alaska $33.48 $18.61
Canada $28.44 $16.52
Average $29.90 $18.17
Natural gas (per mcf)
U.S. Lower 48 $ 5.61 $ 2.47
Alaska $ 1.20 $ 1.57
Canada $ 5.33 $ 2.25
Average $ 5.25 $ 2.35
----------------------------------------------------------------------------
(a) Includes proportional interests in production of equity investees.
(b) Includes minority interests of :
Liquids 1 9
Natural gas 10 98
Barrels oil equivalent 2 25
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as
hedges and ineffective portions of hedges.
-28-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION
For the Three Months
Ended March 31,
---------------------------
2003 2002
----------------------------------------------------------------------------
International Net Daily Production (e)
Liquids (thousand barrels)
Far East 55 53
Other (a) 21 20
----------------------------------------------------------------------------
Total liquids 76 73
Natural gas - dry basis (million cubic feet)
Far East 875 822
Other (a) 107 75
----------------------------------------------------------------------------
Total natural gas 982 897
International Average Prices (f)
Liquids (per barrel)
Far East $29.69 $19.28
Other $32.21 $21.96
Average $30.11 $19.86
Natural gas (per mcf)
Far East $ 2.76 $ 2.59
Other $ 2.83 $ 2.48
Average $ 2.77 $ 2.58
----------------------------------------------------------------------------
Worldwide Net Daily Production (a) (b) (e)
Liquids (thousand barrels) 164 172
Natural gas - dry basis (million cubic feet) 1,840 1,834
Barrels oil equivalent (thousands) 471 477
Worldwide Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel) $30.49 $18.80
Natural gas (per mcf) $ 4.17 $ 2.37
Worldwide Average Prices (including hedging activities) (c) (d)(f)
Liquids (per barrel) $ 29.99 $18.86
Natural gas (per mcf) $ 3.90 $ 2.46
----------------------------------------------------------------------------
(a) Includes proportional interests in production of equity investees.
(b) Includes minority interests of :
Liquids 1 9
Natural gas 10 98
Barrels oil equivalent 2 25
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as
hedges and ineffective portions of hedges.
(e) International production is presented utilizing the economic
interest method.
(f) International did not have any hedging activities.
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Exploration and Production
The Company engages in oil and gas exploration, development and production
worldwide. The results of this segment are discussed under the following two
geographical breakdowns:
North America - Included in this category are the U.S. Lower 48, Alaska and
Canada oil and gas operations. The emphasis of the U.S. Lower 48 operations is
on the onshore, the shelf and deepwater areas of the Gulf of Mexico region and
the Permian and San Juan Basins in west Texas and New Mexico. A substantial
portion of the crude oil and natural gas produced in the U.S. Lower 48
operations, excluding production from the Company's Pure Resources, Inc.
("Pure") subsidiary, is sold to the Company's Trade business segment. Natural
gas produced by Northrock in Canada is also sold to the Company's Trade business
segment. The remainder of U.S. Lower 48 and Canada production is sold to third
parties. In Alaska, natural gas production, pursuant to agreements with the
purchaser of the Company's former agricultural products business, is sold to a
fertilizer plant in Nikiski, Alaska. In addition, the Company uses hydrocarbon
derivative financial instruments such as futures, swaps and options to hedge
portions of the Company's exposure to commodity price fluctuations.
First Quarter Results: Earnings from continuing operations were $150 million in
the first quarter of 2003 compared to a loss of $11 million for the same period
a year ago, which was an increase of $161 million. The increase was primarily
due to higher natural gas and liquids prices, which increased net earnings by
approximately $130 million and $55 million, respectively. North America's
average realized natural gas price, including a loss of 58 cents per Mcf from
hedging activities, was $5.25 per Mcf for the first quarter of 2003. This was an
increase of $2.90 per Mcf, or 123 percent, from the $2.35 per Mcf, including a
benefit of 19 cents per Mcf from hedging activities, realized during the first
quarter of 2002. In the first quarter of 2003, North America's worldwide average
realized liquids price was $29.90 per Bbl, which was an increase of $11.73 per
Bbl, or 65 percent, from the same period a year ago. The Company's hedging
program lowered the average realized liquids price by 87 cents per Bbl in the
first quarter of 2003 while the first quarter of 2002 included a gain of 11
cents per Bbl from hedging activities. The first quarter of 2003 included an
after-tax gain of $2 million in mark-to-market accruals and realized
gains/losses for non-hedge commodity derivatives recorded by the Company's
Northrock subsidiary, compared to an after-tax loss of $4 million in the same
period a year ago.
These positive factors were partially offset by higher dry hole costs, lower
natural gas and liquids production, and higher DD&A rates, which reduced
after-tax earnings by approximately $25 million, $15 million and $10 million,
respectively. Dry hole costs were higher due to the Bohr prospect located on
Mississippi Canyon Block 637 in the deepwater Gulf of Mexico. North America
average net daily natural gas production was 858 MMcf/d in the first quarter
of 2003 compared to 937 MMcf/d in the same period a year ago, which was a
decrease of 8 percent. The average net daily liquids production was 88 MBbl/d
in the first quarter of 2003 compared to 99 MBbl/d in the same period a year
ago, which was a decrease of 11 percent. This decrease was primarily
attributable to natural declines in existing fields in the Gulf of Mexico and
included the impact of about 5 MBOE/d from the divestiture of various properties
in Canada, onshore U.S. and the Gulf of Mexico. Natural gas production in Alaska
decreased 40 percent from a year ago due to natural declines in existing fields.
International - Unocal's International operations include oil and gas
exploration and production activities outside of North America. The Company
operates or participates in production operations in Thailand, Indonesia,
Myanmar, Bangladesh, the Netherlands, Azerbaijan, the Democratic Republic of
Congo and Brazil. International operations also include the Company's
exploration activities and the development of energy projects primarily in Asia,
Australia, Latin America and West Africa.
First Quarter Results: Earnings from continuing operations totaled $142 million
in the first quarter of 2003 compared to $102 million in the same period a year
ago, which was an increase of $40 million. The increase was due to $35 million
in higher liquids prices, $10 million in higher natural gas prices and $10
million in higher natural gas production. These positive factors were partially
offset by approximately $10 million in higher DD&A expense (including asset
retirement obligation accretion). The average liquids price for International
operations was $30.11 per Bbl in the first quarter of 2003, which was an
increase of $10.25 per Bbl, or 52 percent, from the same period a year ago.
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The average natural gas price for International operations was $2.77 per Mcf,
which was an increase of 19 cents, or 7 percent, from the same period a year
ago. Natural gas production in International operations was 982 MMcf/d in the
first quarter of 2003 compared to 897 MMcf/d in the same period a year ago. This
increase was primarily the result of higher demand from Thailand and Bangladesh.
TRADE
The Trade segment externally markets the majority of the Company's worldwide
liquids production, excluding that of Pure, and North American natural gas
production, excluding that of Pure and the Alaska business unit. It is also
responsible for executing various derivative contracts on behalf of the
Exploration and Production segment in order to manage the Company's exposures to
commodity price changes. The Trade segment also purchases liquids and natural
gas from certain of the Company's royalty owners, joint venture partners and
unaffiliated oil and gas producing and trading companies for resale. In
addition, the segment trades hydrocarbon derivative instruments, for which hedge
accounting is not used, to exploit anticipated opportunities arising from
commodity price fluctuations. The segment 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.
First Quarter Results: The results for the first quarter of 2003 were a loss of
$9 million after-tax from continuing operations compared to after-tax earnings
of $1 million in the same period a year ago. The lower results reflect losses
from crude oil and natural gas trading activities, which were negatively
impacted by extremely volatile commodity prices experienced during the first
quarter of 2003.
Sales and operating revenues were $920 million in the first quarter of 2003
compared to $456 million in the same period a year ago, which was an increase of
$464 million. These revenues represented approximately 52 percent and 45 percent
of the Company's total sales and operating revenues for the first quarters of
2003 and 2002, respectively. In the first quarter of 2003, crude oil revenues
increased by approximately $210 million and natural gas revenues increased by
approximately $255 million, primarily due to higher commodity prices.
MIDSTREAM
The Midstream segment is comprised of the Company's equity interests in certain
petroleum pipeline companies, wholly-owned pipeline systems throughout the U.S.,
and the Company's North America gas storage business.
First Quarter Results: Earnings from continuing operations totaled $18 million
in the first quarter of 2003 compared to $19 million in the same period a year
ago. The decrease was due primarily to $3 million in expenses related to the
construction of the Baku-Tbilisi-Ceyhan ("BTC") pipeline project. This negative
factor was mostly offset by improved results in the gas storage business.
GEOTHERMAL AND POWER OPERATIONS
The Geothermal and Power Operations business 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.
The Company's non-exploration and production business development activities,
primarily power-related, are also included in this segment.
First Quarter Results: Earnings from continuing operations totaled $12 million
in the first quarter of 2003 compared to $6 million in the same period a year
ago. The current period results benefited from the impact of higher power
generation in Indonesia under the amended Salak agreements. The first quarter
of 2002 included net losses related to the Company's equity interest in natural
gas-fired power plants in Thailand.
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CORPORATE AND OTHER
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate activities, carbon and minerals) and other
corporate unallocated costs (including environmental and litigation expense).
Net interest expense represents interest expense, net of interest income and
capitalized interest.
First Quarter Results: The results for the first quarter of 2003 was a loss of
$96 million compared to a loss of $95 million in the same period a year ago.
The results in the first quarter of 2003 for the carbon, minerals and real
estate business activities were $6 million lower than the same period a year
ago. In addition, the first quarter of 2003 reflected approximately $5 million
in higher pension related expenses. Lower after-tax expenses for environmental
and litigation matters benefited the first quarter of 2003, with expenses of
$17 million after-tax compared to $23 million after-tax for the same period a
year ago. Net interest expense was $6 million lower in the first quarter of 2003
compared to the same period a year ago, primarily due to higher capitalized
interest on development projects.
FINANCIAL CONDITION
Cash flows from operating activities, including working capital and other
changes, were $685 million for the three months ended March 31, 2003, compared
with $271 million for the same period a year ago. The increase principally
reflected the effects of higher worldwide commodity prices.
Pre-tax proceeds from asset sales were $66 million for the three months ended
March 31, 2003. The Company completed the sale of various properties in Canada,
onshore U.S. and the Gulf of Mexico, which netted the Company $64 million in
proceeds. Pre-tax proceeds from asset sales for the three months ended March 31,
2002, including those classified as discontinued operations, were $30 million
and primarily reflect the sale by the Company's Pure subsidiary of oil and
gas producing properties in the U.S.
Capital expenditures were $429 million for the first quarter of 2003 compared
with $390 million in the same period a year ago. Capital expenditures for 2003
are currently forecast at approximately $1.7 billion, essentially unchanged from
2002. In the first quarter of 2003, the Company's capital expenditures included
approximately $215 million for the development of undeveloped proved oil and gas
reserves.
The Company's total consolidated debt, including current maturities, at March
31, 2003, was $2.92 billion, compared with $3.0 billion at the end of 2002. This
decrease primarily reflected the retirement of $89 million in 9.25% debentures
which matured during the first quarter and $10 million of maturing medium-term
notes (see note 10 for further detail on the Company's long-term debt). Cash and
cash equivalents on hand totaled $356 million at March 31, 2003, up from $168
million at the end of 2002.
The Company has two credit facilities in place: a $400 million 364-day credit
agreement and a $600 million 5-year credit agreement. 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
preferred securities 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, 2003, the borrowing under the credit facility translated
to $201 million, using applicable foreign exchange rates.
Based on current commodity prices and current development projects, the Company
expects cash generated from operating activities, asset sales and cash on hand
in 2003 to be sufficient to cover its operating and capital spending
requirements and to meet dividend payments and to pay down debt. Further, the
Company has substantial borrowing capacity to enable it to meet unanticipated
cash requirements.
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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, 2003, the Company had sold $33 million of its domestic trade
receivables under its accounts receivable securitization program, which was a
decrease of $75 million from the $108 million level that was sold at year-end
2002. The Company also had in place a universal shelf registration statement as
of March 31, 2003, 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. Moody's and Standard & Poor's
outlooks remained stable for the Company's Prime-2 and A-2 commercial paper
ratings, respectively. The Company does not believe it has a significant
exposure to liquidity risk in the event of a credit rating downgrade.
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 remediation obligations have been
accrued in a reserve for such obligations. At March 31, 2003, the Company's
remediation reserve totaled $249 million, of which $131 million was included in
current liabilities. During the three months ended March 31, 2003, cash payments
of $11 million were applied against the reserve and $15 million in provisions
were added to the reserve. 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 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 Company's total environmental reserve and possible additional liability
amounts are grouped into the following four categories.
At March 31, 2003
----------------------------
Possible
Additional
Millions of dollars Reserve Costs
--------------------------------------------------------------------------------
Superfund and similar sites $ 17 $ 10
Active Company facilities 34 25
Company facilities sold with retained liabilities
and former Company-operated sites 102 80
Inactive or closed Company facilities 96 100
--------------------------------------------------------------------------------
Total $ 249 $ 215
================================================================================
Also see notes 12 and 13 to the consolidated financial statements in Item 1 of
this report for additional information on environmental related matters.
-33-
In the first quarter of 2003, provisions of $11 million were recorded for the
"Inactive or closed Company facilities" category of sites, primarily for
remediation projects at the Company's former refinery in Beaumont, Texas. The
Company has been working with the Texas Commission on Environmental Quality
("TCEQ") to develop plans for closing impoundments used in the site's former
operations and for other remediation projects. In the first quarter, Company
recorded a provision for the revised estimated costs of the impoundment closure
plan based on the TCEQ initial draft permit that was issued in the first
quarter.
In the first quarter of 2003, estimated possible additional remediation costs
decreased by $30 million. The net decrease was primarily for sites in the
"Active Company facilities" category. This decrease was the result of the
reclassification of costs to asset retirement obligations under SFAS No. 143 for
the Company's Molycorp subsidiary (see note 2 for further detail).
Possible additional remediation costs for the "Inactive or closed Company
facilities" category decreased by $5 million. This decrease was related to
estimated remediation costs for the Company's former Beaumont, Texas refinery.
Previously identified possible additional costs were included in the reserve for
this site in the first quarter of 2003 as discussed above.
Partially offsetting the foregoing decreases was an increase of $5 million in
possible additional costs for the "Company facilities sold with retained
liabilities and former Company-operated sites" category. This increase was
primarily for costs that may be incurred related to the cleanup of various sites
that were part of the auto/truckstop system that the Company sold in 1993.
OUTLOOK
Certain of the statements in this discussion, as well as other forward-looking
statements within this document, contain estimates and projections of amounts of
or increases/decreases in future revenues, earnings, cash flows, capital
expenditures, assets, liabilities and other financial items and of future levels
of or increases/decreases in reserves, production, sales including related costs
and prices, drilling activities and other statistical items; plans and
objectives of management regarding the Company's future operations, products and
services; and certain assumptions underlying such estimates, projection plans
and objectives. While these forward-looking statements are made in good faith,
future operating, market, competitive, legal, economic, political,
environmental, and other conditions and events could cause actual results to
differ materially from those in the foward-looking statements. See pages 56
through 64 of Management's Discussion and Analysis in Item 7 of the Company's
2002 Annual Report on Form 10-K for a discussion of certain of such conditions
and events.
The economic situation in Asia, where most of the Company's international
activity is centered, is still recovering with positive signs showing in the
region. The Company looks at the natural gas market in Asia as one of its major
strategic investments and believes that the governments in the region are
committed to undertaking the reforms and restructuring necessary to enable their
nations to continue their recoveries from the downturn. Volatile energy prices
are expected to continue to impact financial results. The Company expects energy
prices to remain volatile due to changes in climate conditions, worldwide
demand, crude oil and natural gas inventory levels, production quotas set by
OPEC, current and future worldwide political instability, especially recent
events concerning Iraq, Nigeria and Venezuela, security and other factors.
The Company currently estimates its full-year 2003 production to average between
475,000 to 490,000 BOE per day. This production forecast includes the associated
production loss of approximately 5,000 BOE per day from divestitures that the
Company has completed so far this year. The Company has additional property
divestitures pending or planned and additional adjustments to the production
forecast range will be made as further divestitures are completed. The
production forecast reflects the start of new oil production from the West Seno
field in Indonesia, currently scheduled to begin late in the second quarter of
2003. The Company's total actual production for the year could also be impacted
by cost recovery volume fluctuations under the Company's various foreign PSCs
due to changes in commodity prices, demand for natural gas in Thailand, and
production and exploration performance in the Gulf of Mexico. For the remaining
three quarters of 2003, the Company has hedged 43.4 billion Btus of Lower 48
natural gas production with collars of $3.98 to $4.84 per MMBtu. This volume
represents approximately 25 percent of expected Lower 48 natural gas production.
The Company has hedged 1.5 million barrels of Lower 48 crude oil with collars
between $28.94 and $32.71 per barrel in the second quarter of 2003, which
represents 35 percent of
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expected Lower 48 crude oil production. Hedged crude oil production volumes
beyond the second quarter levels are immaterial. Based on current prices, the
Company's net earnings for the full-year are expected to change 14 cents per
share for each $1 change in the Company's average worldwide realized price for
crude oil and 7 cents per share for every 10-cent change in its average realized
North America natural gas price, excluding the effect of hedging activities. The
Company forecasts pre-tax dry hole costs of $155 million to $185 million and
that pre-tax pension-related expenses will increase over 2002 by approximately
$55 million to $60 million.
Exploration and Production - North America
U.S. Lower 48
The Company had two discoveries late in 2002 and one in 2003 in the deep shelf
in the Gulf of Mexico, and it expects to continue its deep shelf program in the
Gulf of Mexico with 9 to 15 additional wells in the remaining months of 2003.
In the Gulf of Mexico deepwater, the Company plans to continue funding the
development of the Mad Dog discovery in which the Company has a 15.6 percent
non-operating working interest. The Company anticipates first production in late
2004 or early 2005, with gross expected production of 75 MBbl/d of liquids and
35 MMcf/d of natural gas in 2007. The Company expects the co-venture integrated
project team of the K-2 discovery to have a development plan in 2003. The
Company also expects to drill 2 or 3 more wells in the Gulf of Mexico deepwater
in the remaining months of 2003. The Company is currently drilling the Champlain
prospect located on the Atwater Valley Block 63. The Company is participating in
an appraisal well, which will earn it a 30 percent interest in the discovery by
paying for 50 percent of the well costs. The Champlain prospect is strategic to
the Company because of its proximity to the Mirage discovery, located on
Mississippi Canyon Block 941, where it has a 25 percent non-operating working
interest.
The Company continues to move forward with studies on development options for
its Trident discovery in the deepwater Gulf of Mexico. The Company is having
conversations with all the operators in the area about development scenarios and
joint development planning. The Company is the operator of the discovery and has
a 59.5 percent working interest in a seven-block area.
The Company has sold and anticipates selling more of its lower margin properties
in the U.S. in 2003.
Alaska
The Ninilchik Unit development in the South Kenai Peninsula is progressing.
First production from the Ninilchik Unit is also expected in the fourth quarter
of 2003, with that early production going to the Kenai Gas Storage Facility for
delivery to customers beginning in the first quarter of 2004. The Company has a
40 percent non-operating interest in the unit. The Company is also planning to
drill at least one new exploration well on the Kenai Peninsula in 2003.
Exploration and Production - International
Far East
Thailand: Demand for natural gas from the Company's fields has been very strong
as a result of the ongoing reduced production from adjacent fields operated by
PTT Exploration and Production PLC ("PTTEP"), and the Company expects that
demand to continue. The Company expects higher average liquids production, with
the full-year effect of crude oil production from its Yala field. The Company
has a 71 percent working interest in the Yala field (62 percent net of royalty).
The Company's plans are geared towards exploring for additional oil and gas
resources in the Gulf of Thailand and supporting the efforts of PTTEP in the
development of the Arthit gas field in the gulf. The Company has a 16 percent
working interest in the Arthit gas field.
-35-
Indonesia: The Company expects new production from the deepwater West Seno oil
and gas field to come on line in late June or early July 2003. Gross daily
production from the first phase of development is expected to reach about 35
MBOE to 40 MBOE by the end of 2003, increasing to a peak production level of
approximately 60 MBbl/d of oil and 150 MMcf/d of natural gas (gross) in late
2005 with the second phase of development. Gross development costs for the first
phase are expected to be approximately $500 million, with an additional $240
million for the second phase (Unocal's net share is expected to be approximately
$450 million and $215 million for the first and second phases, respectively).
The Company and its co-venturer completed financing arrangements for a portion
of the total costs through the Overseas Private Investment Corporation in late
March 2003 through two loans. One loan is $300 million for the first phase, and
the other loan is $50 million for the second phase. The loan associated with the
second phase is still subject to a final construction contract being obtained.
The Company's Unocal Rapak, Ltd. ("Unocal Rapak"), subsidiary is continuing its
evaluation of engineering and development studies for the deepwater Ranggas oil
prospect offshore East Kalimantan, Indonesia. The Company expects to complete
the pre-development engineering to determine if Ranggas is a commercial
development later in 2003. Unocal Rapak is operator of the Rapak PSC area and
holds an 80 percent working interest. The Company began testing the oil
potential of structures south of the main Ranggas discovery area in the second
quarter of 2003. The Company is also evaluating early development options for
the condensate discovered at its deepwater Gendalo-Gandang discovery in the
Ganal PSC, offshore East Kalimantan. The Company's Unocal Ganal, Ltd.,
subsidiary is the operator of the Ganal PSC and holds an 80 percent working
interest.
The Company will drill a deep well in the Sadewa field in the East Kalimantan
PSC area to test for oil. The Sadewa discovery well was drilled in 2002 and
found both natural gas and oil. The oil play found near the bottom of the well
provided encouragement for deeper oil potential that could not be fully
evaluated at the time. The Company holds a 50 percent working interest in the
well.
The Company is also participating in the Donggala PSC, in which it had acquired
a 19.55% non-operating working interest in early 2003. The Donggala PSC lies
adjacent to and east of the Rapak PSC area.
China: The Company has worked with China National Offshore Oil Corporation,
China New Star Petroleum Corporation, the Shanghai Municipality and the State
Planning Commission to promote appraisal and development of natural gas
resources in the Xihu Trough, off the coast of Shanghai, in the East China Sea.
Unocal believes the area could contain significant amounts of recoverable
natural gas. The Company is continuing its negotiations and is still expecting
to sign PSCs in 2003 to explore and develop natural gas resources. The Company's
working interest is expected to be 20 percent.
Other International
Azerbaijan: The Azerbaijan International Operating Company ("AIOC") consortium,
in which the Company has a 10.28% working interest, is on track with its
development of Phases I and II of the offshore Azeri field in the
Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea. The
project is under construction and on schedule with first oil from the Phase 1
Central Azeri platform expected early in 2005. A third phase is in early
engineering and is expected to be approved in 2004. Gross production from the
combined phases, plus the currently producing Early Oil Project in the Chirag
Field, is forecasted to be over 1 MMBbl/d (gross) by 2009. This forecast is
contingent upon the completion of the BTC pipeline project and the general
political risks inherent to the region. The multi-country nature of this
pipeline along with multinational participation in the consortium, in addition
to expected project financing from international lending institutions like the
IFC and EBRD and from several export credit agencies, should help to mitigate
the political risk.
Bangladesh: Domestic sales in the country have expanded and the Company is
working on amending agreements to increase the Take-or-Pay volume for natural
gas sold to Petrobangla, the state oil and gas company. The Company also
continues to work with the government of Bangladesh and Petrobangla to develop
additional reserves and export natural gas to markets in neighboring India. At
April 30, 2003, the Company's business unit in Bangladesh had a gross receivable
balance of approximately $29 million relating to invoices billed for natural gas
and condensate sales to Petrobangla. Approximately $23 million of the
-36-
outstanding balance represented past due amounts and accrued interest for
invoices covering November 2002 through March 2003. Generally, invoices, when
paid, have been paid in full. The Company is working with Petrobangla and the
government of Bangladesh regarding the collection of the outstanding
receivables.
Midstream
Physical construction of the BTC pipeline began in April 2003. The pipeline
project is planned to have a crude oil throughput capacity of 1 million Bbl/d.
Completion of the pipeline is expected in late 2004 at an overall estimated cost
of approximately $3 billion, and the pipeline is expected to be in operation in
early 2005. The Company has an 8.9 percent interest and is one of eleven
shareholders in the BTC pipeline project. The pipeline company anticipates
financing up to 70 percent of the pipeline's cost.
The Kenai Kachemak Pipeline, currently under construction, will transport
natural gas from Ninilchik to Kenai, where it will tie into the existing gas
grid serving south central Alaska. The Company expects the 32-mile pipeline to
be in operation in the fourth quarter of 2003.
Geothermal and Power Operations
In the Philippines, the Company's wholly-owned subsidiary Philippine Geothermal,
Inc. and two government-owned entities, the National Power Corporation, the
Power Sector Assets and Liabilities Corporation and the Philippine Department of
Energy signed a compromise settlement agreement covering the definitive terms of
settlement in March 2003. The parties are now in the process of securing all
necessary Philippine government and court approvals of the settlement.
Major flooding and landslides caused by heavy rains at the Gunung Salak
geothermal project area on Java in Indonesia during early May has resulted in
damage to some of geothermal steam production and electric power generation and
transmission facilities. As a result of the damage, electricity generation for
the second and third quarters of 2003 is expected to be reduced significantly.
The Company is currently assessing the full impact of the damage, alternative
repair options and the anticipated impact on segment earnings.
The Company is in discussions with PT. PLN (Persero) concerning the Sarulla
geothermal project in the island of Sumatra, Indonesia.
FUTURE ACCOUNTING CHANGES
FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities." (see note
2 to the consolidated financial statements in Item 1 of this report). The
effective date for the consolidation of entities existing prior to February 1,
2003 is July 1, 2003. The Company expects the adoption of the recognition (i.e.,
consolidation) requirements of the Interpretation to increase its consolidated
long-term debt by approximately $320 million in the third quarter of 2003. This
amount will include $242 million related to a partnership interest in which the
Company currently has a minority interest liability (see note 11 to the
consolidated financial statements in Item 1 of this report) and $78 million of
third-party debt of DSPL (see note 11 to the consolidated financial statements
in Item 1 of this report).
SFAS No. 149: In April 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." This Statement
amends and clarifies accounting for derivative instruments including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. SFAS No. 149 is effective for contracts entered into or
modified after June 30, 2003. The Company is currently in the process of
evaluating the impact of this pronouncement.
Other proposed accounting changes considered from time to time by the FASB, the
SEC and the United States Congress could materially impact the Company's
reported financial position and results of operations.
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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, 2003. Assuming a ten percent decrease in the
Company's weighted average borrowing costs at March 31, 2003, 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 $100 million at March 31, 2003.
-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.
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,
2003, the Company had various foreign currency swaps and foreign currency
forward contracts outstanding related to operations in Canada, 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 and
forward contracts. Assuming an adverse change of ten percent in foreign exchange
rates at March 31, 2003, the potential decrease in fair value of the Company's
foreign currency forward contracts, foreign-currency denominated debt, foreign
currency swaps and foreign currency forward contracts of its subsidiaries, would
have been approximately $34 million at March 31, 2003.
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 $15
million at March 31, 2003. The value at risk related to hydrocarbon derivatives
held for non-hedging purposes was approximately $5 million at March 31, 2003.
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, 2003, along with the
fair values of those instruments.
-39-
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
2003 2004 2005 2006 2007-2008 Fair Value
Asset(Liability)(b)(c)
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 530,000 - - - - $ 1,385
Average price, per MMBtu $ 4.99
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 5,953,000 7,511,000 7,218,000 7,218,000 14,459,000 $ 60,701
Average swap price, per MMBtu $ 2.58 $ 2.43 $ 2.37 $ 2.42 $ 2.50
Receive fixed price
Volume (MMBtu) - - - - - $ 2,458
Average swap price, per MMBtu $ -
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 16,180,000 - - - - $ 2,000
Average price received, per MMBtu $ 4.82
Average price paid, per MMBtu $ 4.70
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) 38,426,000 268,500 - - - $ (27,021)
Average ceiling price, per MMBtu $ 4.66 $ 5.45
Average floor price, per MMBtu $ 3.79 $ 2.82
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (OTC)
Put Volume (MMBtu) (21,400,000) - - - - $ 2,185
Average Put Price $ 3.25
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (815,000) - - - - $ (714)
Average price, per Bbl $ 31.45
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) (1,600,000) (720,000) - - - $ (413)
Average price, per Bbl $ 24.00 $ 20.00
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Collar Positions
Volume (Bbls) 2,511,500 810,000 - - - $ 1,703
Average ceiling price, per Bbl $ 32.70 $ 28.16
Average floor price, per Bbl $ 28.42 $ 23.41
------------------------------------------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Net claims against counterparties with non-investment grade credit ratings are immaterial.
(c) Includes $6,754 thousand in assumed liabilities which were capitalized as acquisition costs.
-40-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
2003 2004 Fair Value
Asset(Liability) (b)
----------------------------------------------------------------------------------------------- --------------- --------------------
Natural Gas Futures Positions
Volume (MMBtu) 5,500,000 - $ (6,739)
Average price, per MMBtu $ 5.50
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 6,360,000 - $ 175
Average swap price, per MMBtu $ 5.20
Receive fixed price
Volume (MMBtu) 5,091,375 95,438 $(11,502)
Average swap price, per MMBtu $ 4.59 $ 1.99
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 16,500,000 - $ 4,520
Average price received, per MMBtu $ 4.82 $ -
Average price paid, per MMBtu $ 4.52 $ -
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Swap Positions
Volume (MMBtu) 3,510,000 3,640,000 $ 4,044
Average price received, per MMBtu $ 0.59 $ 0.54
Average price paid, per MMBtu $ 0.79 $ 1.46
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) (6,250,000) - $ 2,023
Average Call price $ 6.08 $ -
Put Volume (MMBtu) (1,600,000) - $ (1,244)
Average Put Price $ 5.97 $ -
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Over the Counter)
Call Volume (MMBtu) (3,650,700) - $ (5,542)
Average Call price $ 4.08 $ -
Put Volume (MMBtu) (3,940,000) (1,820,000) $ (39)
Average Put price $ 3.97 $ 4.50
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Call Volume (MMBtu) (1,000,000) - $ 49
Average Strike price $ 0.60 $ -
Put Volume (MMBtu) (7,000,000) - $ 158
Average Strike price $ 0.25 $ -
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 721,000 - $ 349
Average price, per Bbl $ 35.27
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) - - $ (230)
Average price, per Bbl $ -
Call Volumes (Bbls) (100,000) - $ 255
Average price, per Bbl $ 42.50
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Calender Spread)
Put Volume (Bbls) 200,000 - $ (138)
Average price, per Bbl $ 0.80 $ -
Call Volumes (Bbls) (200,000) - $ (8)
Average price, per Bbl $ 0.93 $ -
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) (4,559,540) - $ (3,048)
Average swap price, per Bbl $ 30.45
Receive fixed price
Volume (Bbls) 3,959,540 - $ 3,997
Average swap price, per Bbl $ 30.69
------------------------------------------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $7,476 thousand net claims against counterparties with non-investment grade credit ratings.
(c) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside FERC Gas Report (IFERC).
-41-
ITEM 4. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, the Company carried out an
evaluation of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Rule 13a-14 of the Securities
Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded 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 were no significant changes in the Company's internal controls or other
factors that could significantly affect these controls subsequent to the date of
their evaluation and there were no corrective actions required with regard to
significant deficiencies and material weaknesses.
-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, 2002. There is incorporated
by reference: the information regarding the environmental remediation reserve
and possible additional remediation costs in notes 12 and 13 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 13 to the
consolidated financial statements.
Information with respect to recent developments in certain previously reported
proceedings is set forth below:
1. In the California Superior Court cases (the Doe and Roe cases) alleging the
Company's liability in connection with the construction of the natural gas
pipeline from the Yadana field across Myanmar to the Thailand border,
described in Paragraph 2 of Item 3 of the 2002 Form 10-K, the court has
bifurcated the trial. Phase I will address choice of law and whether the
correct corporate defendants are before the court. If Unocal is
unsuccessful in Phase I, then Phase II will address liability. Phase I is
scheduled for July 2003 and Phase II for December 2003.
The Company believes that the outcomes of the federal and state cases are
not likely to have a material adverse effect on the Company's financial
condition or liquidity or, based on management's current assessment of the
cases, the Company's results of operations.
Certain Environmental Matters Involving Civil Penalties
2. The Environmental Protection Agency ("EPA") and Unocal have entered into a
civil settlement regarding the EPA's claims that Unocal violated the
National Pollutant Discharge Elimination System (NPDES) general permit
concerning the discharge of produced water and sanitary waste in Cook
Inlet. The EPA claimed that Unocal violated the permit conditions in 65
separate instances at 11 different facilities located in Cook Inlet,
Alaska. Some of the alleged violations include a monthly reporting period,
and therefore qualify as daily violations for the entire standard 30-day
month. The alleged violations consist of procedural failures such as
failure to take samples or errors in reporting sample testing, and
substantive failures such as discharges which exceeded the permit limits.
On May 8, 2003, Unocal and the EPA have executed a Consent Agreement with
respect to each affected facility. The settlement will be noticed in an
Anchorage, Alaska, newspaper, and will be subject to public comment before
final approval. The total amount of the fine imposed pursuant to the
settlement agreement is $370,000, of which Unocal will pay $189,389 and the
remainder will be paid by working interest owners in the affected
facilities.
-43-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 48 of this report lists the
exhibits that are filed as part of this report.
(b) Reports on Form 8-K:
Filed during the first quarter of 2003:
(1) Current Report on Form 8-K, dated January 28, 2003 and filed
February 5, 2003, for the purpose of reporting, under Item 5, the
Company's fourth quarter and full-year 2002 earnings and related
information, the Company's 2002 reserve replacement and finding
development and acquisitions costs, the Company's 2003 outlook
and other operational activity updates.
(2) Current Report on Form 8-K, dated February 4, 2003 and filed
February 10, 2003, for the purpose of reporting, under Item 5,
the Company's designation of its Vice President and Chief Legal
Officer as an "executive officer."
(3) Current Report on Form 8-K, dated March 26, 2003 and filed April
1, 2003, for the purpose of reporting, under Item 5, the
Company's drilling results of a well in the Gulf of Mexico, and
under Item 7, the amendments and interpretations of certain
compensation plans.
Filed during the second quarter of 2003 to the date hereof:
(1) Current Report on Form 8-K, dated April 1, 2003, and filed April
2, 2003, for the purpose of reporting, under Item 5 and Item 7,
an amendment to Unocal's Rights Agreement.
(2) Current Report on Form 8-K, dated April 24, 2003, and filed April
28, 2003, for the purpose of reporting, under Item 5, the
Company's first quarter 2003 earnings and related information and
the Company's 2003 outlook.
-44-
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 12, 2003 By: /s/JOE D. CECIL
------------------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer and
Principal Accounting Officer)
-45-
CERTIFICATIONS
I, Charles R. Williamson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Unocal
Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 12, 2003
/s/CHARLES R. WILLIAMSON
----------------------------
Charles R. Williamson
Chairman of the Board
and Chief Executive Officer
-46-
CERTIFICATIONS
I, Terry G. Dallas, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Unocal
Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: May 12, 2003
/s/ TERRY G. DALLAS
---------------------------
Terry G. Dallas
Executive Vice President
and Chief Financial Officer
-47-
EXHIBIT INDEX
10.1 Amendment No. 3 to Rights Agreement between Unocal and Mellon
Investor Services, L.L.C., as Rights Agent dated as of April 1, 2003
(incorporated by reference to Exhibit 10 to Unocal's Current Report
on Form 8-K dated April 1, 2003, File No. 1-8483).
10.2 Form of Director Indemnity Agreement between Unocal and each of its
directors.
10.3 Form of Officer Indemnity Agreement (restated) between Unocal and each
of its officers which had existing Indemnity Agreements.
10.4 Form of Officer Indemnity Agreement (new) between Unocal and each of
its officers which did not have existing Indemnity Agreements.
10.5 Amendments and interpretations of certain compensation plans effective
October 1, 2002 (incorporated by reference to Exhibit 10 to Unocal's
Current Report on Form 8-K dated March 26, 2003, File No. 1-8483).
12.1 Statement regarding computation of ratio of earnings to fixed charges
of Unocal Corporation for the three months ended March 31, 2003 and
2002.
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,
2003 and 2002.
Copies of exhibits will be furnished upon request. Requests should be
addressed to the Corporate Secretary.
-48-