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 June 30, 2002
--------------------
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
------- -------
Number of shares of Common Stock, $1 par value, outstanding as of
July 31, 2002: 244,665,162
TABLE OF CONTENTS
PAGE
Glossary.................................................................... ii
PART I
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....................... 29
Operating Highlights ............................................... 33
Item 3. Quantative and Qualitative Disclosures About Market Risk............ 44
PART II
Item 1. Legal Proceedings................................................... 48
Item 4. Submission of Matters to a Vote of Security Holders................. 49
Item 5. Other Information................................................... 49
Item 6. Exhibits and Reports on Form 8-K.................................... 50
SIGNATURES.................................................................. 50
EXHIBIT INDEX............................................................... 51
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
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 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).
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 believed to be 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 year-end 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.
o Hydrocarbons are organic compounds of hydrogen and carbon atoms that form
the basis of all petroleum products.
ii
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 it can be cooled
or subjected to pressure to facilitate storage and transportation.
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 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 or consortium.
ii
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------------------------------------
Millions of dollars except per share amounts 2002 2001 2002 2001
-----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ 1,349 $ 1,684 $ 2,373 $ 3,890
Interest, dividends and miscellaneous income 8 11 20 19
Gain (loss) on sales of assets (1) 1 1 1
-----------------------------------------------------------------------------------------------------------------------------
Total revenues 1,356 1,696 2,394 3,910
Costs and other deductions
Crude oil, natural gas and product purchases 428 537 723 1,524
Operating expense 312 329 600 659
Administrative and general expense 37 27 80 71
Depreciation, depletion and amortization 255 245 479 468
Impairments 21 - 21 -
Dry hole costs 13 47 41 87
Exploration expense 61 55 120 111
Interest expense 43 48 94 97
Property and other operating taxes 18 20 34 41
Distributions on convertible preferred securities of subsidiary trust 8 8 16 16
-----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 1,196 1,316 2,208 3,074
Earnings from equity investments 51 49 88 91
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 211 429 274 927
-----------------------------------------------------------------------------------------------------------------------------
Income taxes 95 180 135 370
Minority interests 3 14 4 30
-----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 113 235 135 527
Discontinued operations
Refining, marketing and transportation
Gain on disposal (net of tax) 1 12 1 16
-----------------------------------------------------------------------------------------------------------------------------
Earnings from discontinued operations 1 12 1 16
Cumulative effect of accounting change - - - (1)
-----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 114 $ 247 $ 136 $ 542
=============================================================================================================================
Basic earnings per share of common stock (a)
Continuing operations $ 0.46 $ 0.98 $ 0.55 $ 2.17
Net earnings $ 0.46 $ 1.02 $ 0.55 $ 2.23
Diluted earnings per share of common stock (b)
Continuing operations $ 0.46 $ 0.95 $ 0.55 $ 2.11
Net earnings $ 0.46 $ 0.99 $ 0.55 $ 2.17
Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.40 $ 0.40
-----------------------------------------------------------------------------------------------------------------------------
(a) Basic weighted average shares outstanding (in thousands) 244,639 243,508 244,423 243,339
(b) Diluted weighted average shares outstanding (in thousands) 245,865 256,899 245,531 256,655
See Notes to the Consolidated Financial Statements.
-1-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At June 30, At December 31,
--------------------------------------
Millions of dollars 2002 (a) 2001
-------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 161 $ 190
Accounts and notes receivable - net 837 847
Inventories 111 102
Deferred income taxes 138 123
Other current assets 23 33
-------------------------------------------------------------------------------------------------------------------------
Total current assets 1,270 1,295
Investments and long-term receivables - net 1,486 1,405
Properties - net (b) 7,741 7,514
Deferred income taxes 177 128
Other assets 119 83
-------------------------------------------------------------------------------------------------------------------------
Total assets $ 10,793 $ 10,425
=========================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 828 $ 823
Taxes payable 245 249
Dividends payable 49 49
Interest payable 48 49
Current portion of environmental liabilities 116 124
Current portion of long-term debt and capital leases 8 9
Other current liabilities 147 119
-------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,441 1,422
Long-term debt and capital leases 3,111 2,897
Deferred income taxes 678 627
Accrued abandonment, restoration and environmental liabilities 587 590
Other deferred credits and liabilities 722 724
Subsidiary stock subject to repurchase 92 70
Minority interests 430 449
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)) 255 255
Capital in excess of par value 573 551
Unearned portion of restricted stock issued (26) (29)
Retained earnings 2,926 2,888
Accumulated other comprehensive income (66) (88)
Notes receivable - key employees (41) (42)
Treasury stock - at cost (d) (411) (411)
-------------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 3,210 3,124
-------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 10,793 $ 10,425
=========================================================================================================================
(a) Unaudited
(b) Net of accumulated depreciation, depletion and amortization of: $ 11,932 $ 11,648
(c) Number of shares outstanding (in thousands) 244,660 243,998
(d) Number of shares (in thousands) 10,623 10,623
See Notes to the Consolidated Financial Statements.
-2-
CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION
For the Six Months
Ended June 30,
---------------------------------
Millions of dollars 2002 2001
--------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 136 $ 542
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 479 468
Impairments 21 -
Dry hole costs 41 87
Amortization of exploratory leasehold costs 45 45
Deferred income taxes (17) 82
Gain on sales of assets (pre-tax) (1) (1)
Gain on disposal of discontinued operations (pre-tax) (2) (25)
Earnings applicable to minority interests 5 30
Other (45) 62
Working capital and other changes related to operations
Accounts and notes receivable 18 312
Inventories (9) 12
Accounts payable (1) (265)
Taxes payable (4) (46)
Other (40) (59)
--------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 626 1,244
--------------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (830) (824)
Major acquisitions - (417)
Proceeds from sales of assets 45 23
Proceeds from sale of discontinued operations 2 7
--------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (783) (1,211)
--------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Long-term borrowings 440 467
Reduction of long-term debt and capital lease obligations (229) (101)
Minority interests (4) (10)
Proceeds from issuance of common stock 19 13
Dividends paid on common stock (98) (97)
--------------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 128 272
--------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents (29) 305
--------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 190 235
--------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 161 $ 540
==========================================================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 95 $ 98
Income taxes (net of refunds) $ 171 $ 326
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
Commission in Unocal Corporation's 2001 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 six months ended June 30, 2002, are not necessarily indicative
of future financial results.
Certain items in the prior year financial statements have been reclassified to
conform to the 2002 presentation.
2. Accounting Changes
Effective January 1, 2002, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142
addresses accounting for goodwill and identifiable intangible assets subsequent
to their initial recognition, eliminates the amortization of goodwill and
provides specific steps for testing the impairment of goodwill. Separable
intangible assets that are not deemed to have an indefinite life will continue
to be amortized over their useful lives. SFAS No. 142 also eliminates
amortization of the excess of cost over the underlying equity in the net assets
of an equity method investee that is recognized as goodwill. The adoption of the
statement did not have a material effect on the Company's financial position and
results of operations.
Effective January 1, 2002, the Company also adopted SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets", which addresses financial
accounting and reporting for the impairment or disposal of long-lived assets.
SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the
accounting and reporting provisions of Accounting Principles Board Opinion No.
30, "Reporting the Results of Operations--Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions". The adoption of SFAS No. 144 did not have a material
effect on the Company's financial position and results of operations.
The Company has adopted SFAS No. 145, "Rescission of SFAS No. 4, 44, and 64,
Amendment of SFAS No. 13, and Technical Corrections." This Statement rescinds
SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt", and
an amendment of that Statement, SFAS No. 64, "Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements". This Statement also rescinds or amends
other existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. The adoption of SFAS No. 145 did not have a material effect on the
Company's financial position and results of operations.
-4-
In June 2002, the FASB issued 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
and is effective for the Company on January 1, 2003.
3. Other Financial Information
During the second quarters of 2002 and 2001, approximately 23 percent and 25
percent, respectively, of total sales and operating revenues were attributable
to the resale of liquids and natural gas purchased from others in connection
with marketing activities. For the six months ended June 30, 2002 and 2001,
these percentages were approximately 22 percent and 32 percent, respectively.
Related purchase costs are classified as expense in the crude oil, natural gas
and product purchase category on the consolidated earnings statement. The
current year percentage decreases were principally due to lower purchases of
domestic crude oil from third parties for resale. During 2001, management
decided to decrease its outside crude oil purchases for resale due to increased
volatility in the oil markets.
Capitalized interest totaled $10 million and $6 million for the second quarters
of 2002 and 2001, respectively, and $19 million and $11 million for the six
months ended 2002 and 2001, respectively. The increase was primarily due to the
capitalized interest related to the Mad Dog development project in the Gulf of
Mexico and the West Seno oil and gas development project in the deepwater Kutei
Basin, offshore East Kalimantan, Indonesia.
Exploration expense on the consolidated earnings statement consisted of the
following:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
--------------------------- -------------------------
Millions of dollars 2002 2001 2002 2001
----------------------------------------------------------------------------------------------------------------------
Exploration operations $ 25 $ 22 $ 48 $ 40
Geological and geophysical 8 6 19 19
Amortization of exploratory leases 23 23 45 45
Leasehold rentals 5 4 8 7
----------------------------------------------------------------------------------------------------------------------
Exploration expense $ 61 $ 55 $ 120 $ 111
======================================================================================================================
4. Restructuring
In June 2002, the Company 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 approximately 200 employees in the Company's
Sugar Land, Texas, office and field locations. The restructuring plan involves
organizational changes to eliminate unnecessary work processes in the Company's
Gulf Region business unit, which is part of the U.S. Lower 48 operations in the
Exploration and Production segment.
The restructuring charge was reflected in the operating expense line on the
consolidated earnings statement and included approximately $14 million for
termination costs to be paid to the employees over time, about $3 million for
outplacement and other costs and about $2 million for benefit plan curtailment
costs. All of the affected employees had been terminated or had received
termination notices as of June 30, 2002.
5. Impairments
The Company, as part of its regular assessment, reviewed its developed and
undeveloped oil and gas properties and other long-lived assets for possible
impairment. In the second quarter of 2002, the Company recorded a pre-tax charge
of $21 million, or $13 million after-tax, for the impairment of oil and gas
fields in Alaska and the Gulf of Mexico region. The impairment in Alaska, which
made up the majority of the amount recorded, was $18 million pre-tax, or $12
million after-tax.
-5-
6. Income Taxes
Income taxes on earnings from continuing operations for the second quarter and
six months periods of 2002 were $95 million and $135 million, respectively,
compared with $180 million and $370 million for the comparable periods of 2001.
The effective income tax rates for the second quarter and six months periods of
2002 were 46 percent and 50 percent, respectively, compared with 43 percent and
41 percent for the comparable periods of 2001.
The higher effective income tax rates for the second quarter and the first six
months of 2002, as compared with the same periods a year ago, reflect currency
effects primarily in Thailand along with the effect of changes in the mix of
domestic earnings in the prior year periods and losses in the current year
periods coupled with foreign earnings for all periods reported, which are
generally taxed at higher rates.
7. Earnings Per Share
The following are reconciliations of the numerators and denominators of the
basic and diluted earnings per share ("EPS") computations for earnings from
continuing operations for the second quarters and six months ended June 30, 2002
and 2001:
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
---------------------------------------------------------------------------------------------------------------------------
Three months ended June 30, 2002
Earnings from continuing operations $ 113 244.6
Basic EPS $ 0.46
=============
Effect of dilutive securities
Options and common stock equivalents 1.2
--------------------------------
Diluted EPS 113 245.8 $ 0.46
=============
Distributions on subsidiary trust preferred securities (after-tax) 7 12.3
--------------------------------
Antidilutive $ 120 258.1 $ 0.46
Three months ended June 30, 2001
Earnings from continuing operations $ 235 243.5
Basic EPS $ 0.98
=============
Effect of dilutive securities
Options and common stock equivalents 1.1
--------------------------------
235 244.6 $ 0.96
Distributions on subsidiary trust preferred securities (after-tax) 7 12.3
--------------------------------
Diluted EPS $ 242 256.9 $ 0.95
=============
---------------------------------------------------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the three months ended June
30, 2002 and 2001, were options outstanding to purchase approximately 1.9
million and 3.4 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.
-6-
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
---------------------------------------------------------------------------------------------------------------------------
Six months ended June 30, 2002
Earnings from continuing operations $ 135 244.4
Basic EPS $ 0.55
=============
Effect of dilutive securities
Options and common stock equivalents 1.1
--------------------------------
135 245.5 $ 0.55
=============
Distributions on subsidiary trust preferred securities (after-tax) 14 12.3
--------------------------------
Antidilutive $ 149 257.8 $ 0.58
Six months ended June 30, 2001
Earnings from continuing operations $ 527 243.3
Basic EPS $ 2.17
=============
Effect of dilutive securities
Options and common stock equivalents 1.1
--------------------------------
527 244.4 $ 2.16
Distributions on subsidiary trust preferred securities (after-tax) 13 12.3
--------------------------------
Diluted EPS $ 540 256.7 $ 2.11
=============
---------------------------------------------------------------------------------------------------------------------------
The diluted EPS computation for the six months ended June 30, 2002 and 2001, did
not include options outstanding to purchase approximately 3.3 million and 5.0
million shares, respectively, of common stock. These options were not included
in the computation as the exercise prices were greater than the year-to-date
average market price of the common shares.
Basic and diluted earnings per common share for discontinued operations were as
follows:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-------------------------------------------------------
Millions except per share amounts 2002 2001 2002 2001
----------------------------------------------------------------------------------------------------------------------
Basic earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 1 $ 12 $ 1 $ 16
Weighted average common shares outstanding 244.6 243.5 244.4 243.3
Earnings from discontinued operations $ - $ 0.04 $ - $ 0.06
Dilutive earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 1 $ 12 $ 1 $ 16
Weighted average common shares outstanding 245.8 256.9 245.5 256.7
Earnings from discontinued operations $ - $ 0.04 $ - $ 0.06
-7-
8. Comprehensive Income
The Company's comprehensive income was:
For the Three Months For the Six Months
Ended June 30, Ended June 30,
---------------------------------------------------
Millions of dollars 2002 2001 2002 2001
--------------------------------------------------------------------------------------------------------------------------
Net earnings $ 114 $ 247 $ 136 $ 542
Cumulative effect of change in accounting principle
SFAS No. 133 adoption (a) - - - (59)
Change in unrealized loss on hedging instruments (b) (1) 41 (9) 31
Reclassification adjustment for settled hedging contracts (c) 4 2 (1) 19
Unrealized foreign currency translation adjustments 35 15 32 (16)
--------------------------------------------------------------------------------------------------------------------------
Total comprehensive income $ 152 $ 305 $ 158 $ 517
==========================================================================================================================
(a) Net of tax expense (benefit) of: - - - (36)
(b) Net of tax expense (benefit) of: (1) 24 (5) 19
(c) Net of tax expense (benefit) of: 2 1 (1) 11
9. Cash and Cash Equivalents
At June 30, At December 31,
------------------------------------
Millions of dollars 2002 2001
--------------------------------------------------------------------------------------------------------
Cash $ 18 $ 12
Time deposits 97 123
Restricted cash 6 5
Marketable securities 40 50
--------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 161 $ 190
========================================================================================================
10. Long Term Debt and Credit Agreements
During the first six months of 2002, the Company's consolidated debt, including
the current portion, increased by $213 million. This net increase included $440
million in new commercial paper borrowings, the proceeds of which were used to
refinance maturing debt and for general corporate purposes. The commercial paper
had a weighted average interest rate of 2.23 percent at June 30, 2002. The
Company retired $132 million of maturing medium-term notes during the first six
months of 2002. In February 2002, the Company's Northrock Resources Ltd.
subsidiary redeemed its $35 million "Series A" and $40 million "Series B" senior
U.S. dollar-denominated notes, which bore interest of 6.54 percent and 6.74
percent, respectively. The Company's Pure Resources, Inc. ("Pure") subsidiary
reduced its long-term debt, included in the Company's consolidated debt, by $16
million principally due to a decrease in borrowing under its revolving credit
facilities. Pure's debt was $571 million at June 30, 2002. Neither Unocal nor
Union Oil guarantees any of Pure's debt.
11. Accrued Abandonment, Restoration and Environmental Liabilities
At June 30, 2002, the Company had accrued $472 million for the estimated future
costs to abandon and remove wells and production facilities. The total costs for
these abandonments are predominantly accrued on a unit-of-production basis and
are estimated to be approximately $700 million. This estimate was derived in
large part from abandonment cost studies performed by independent third party
firms and is used to calculate the amount to be amortized. The Company's reserve
for environmental remediation obligations at June 30, 2002 totaled $231 million,
of which $116 million was included in current liabilities.
-8-
12. 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 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 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 11, at June 30, 2002, the Company had accrued $231 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 $255 million. The amount of such possible additional
costs reflects the aggregate of the high ends of the ranges of costs of feasible
alternatives identified by the Company for those sites with respect to which
investigation or feasibility studies have advanced to the stage of analyzing
such alternatives. However, such estimated possible additional costs are not an
estimate of the total remediation costs beyond the amounts reserved, because
there are sites where the Company is not yet in a position to estimate all, or
in some cases any, possible additional costs. Both the amounts reserved and
estimates of possible additional costs may change in the near term, and in some
cases could change substantially, as additional information becomes available
regarding the nature and extent of site contamination, required or agreed-upon
remediation methods and other actions by government agencies and private
parties.
-9-
The accrued costs and the possible additional costs are shown below in four
categories of sites:
At June 30, 2002
----------------------------
Possible
Millions of dollars Reserves Additional
-------------------------------------------------------------------------------------------------
Superfund and similar sites $ 18 $ 11
Active company facilities 37 66
Company facilities sold with retained liabilities
and former company-operated sites 97 71
Inactive or closed company facilities 79 107
-------------------------------------------------------------------------------------------------
Total reserves $ 231 $ 255
=================================================================================================
The time frame 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
different 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 a contractual agreement to share remediation
costs with third parties, the reserve reflects the Company's estimated share 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 site. 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 in 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
waste from the current and former operations identified above.
The "Active Company Facilities" category includes oil and gas fields and mining
operations. The 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 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 or impoundments that were used in these operations.
Also, included in these categories are former oil and gas fields that the
company no longer operates. In most cases, these sites are contaminated with
crude oil, oil field waste and other petroleum hydrocarbons. Contamination at
other sites in this category was the result of former industrial chemical and
polymers manufacturing and distribution facilities, agricultural chemical retail
businesses and ferromolybdenum production operations.
-10-
Superfund and similar sites - At June 30, 2002, Unocal had received notification
from the U.S. Environmental Protection Agency ("EPA") that the Company may be a
PRP at 30 sites and may share certain liabilities at these sites. Of the total,
five sites are under investigation and/or litigation and the Company's potential
liability is not presently determinable and for two sites the Company has denied
responsibility. At one site, the Company's potential liability appears to be de
minimis. Of the remaining 22 sites, where probable and to the extent costs can
be reasonably estimated, reserves of $12 million have been established for
future remediation and settlement costs.
Various state agencies and private parties had identified 23 other similar PRP
sites. Two sites are under investigation and/or litigation and the Company's
potential liability is not presently determinable. At three sites the Company's
potential liability appears to be de minimis. At another site, the Company has
made final settlement payments and is in the process of completing its
involvement in the sites. The Company has denied responsibility at two sites.
Where probable and to the extent costs can be reasonably estimated at the
remaining 15 sites, reserves of $6 million have been established for future
remediation and settlement costs.
In addition to the total of $18 million in reserves mentioned above, the Company
has also estimated that additional costs of $11 million are possible for the
"Superfund and Similar Sites" category.
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
These 53 sites exclude 108 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 - The Company has a reserve of $37 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. 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 estimates that it may incur possible additional costs of $67 million
for this group of sites.
Company facilities sold with retained liabilities and former Company-operated
sites - Company facilities sold with retained liabilities include:
o West Coast refining, marketing and transportation sites o Auto/truckstop
facilities throughout the U.S. o Industrial chemical and polymer sites in the
South, Midwest and California o Agricultural chemical sites in the West and
Midwest.
In each sale, the Company retained a contractual remediation or indemnification
obligation and is responsible only for certain environmental problems associated
with its past operations. The reserves represent 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-
-11-
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 $97 million and additional costs of $72 million are
possible for this category. The possible additional costs are primarily related
to service station and distribution facilities and oil and gas properties.
Inactive or closed Company facilities - Reserves of $79 million have been
established for these types of 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.
These sites also have possible additional costs of $95 million associated with
them.
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 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 Beaumont, Texas, facility, a former
agricultural chemical facility in Corcoran, California, and Molycorp's
Washington, Pennsylvania, facility. 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.
Although these costs 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 reserves recorded on the consolidated
balance sheet represent the Company's estimates of assessment and remediation
costs based on currently available facts, existing technology and presently
enacted laws and regulations. The remediation cost estimates, in many cases, are
based on plans recommended to the regulatory agencies for approval and are
subject to future revisions. The ultimate costs to be incurred could exceed the
total amounts reserved. The reserve will be adjusted as additional information
becomes available regarding the nature and extent of site contamination,
required or agreed-upon remediation methods and other actions by government
agencies and private parties. Therefore, amounts reserved may change
substantially in the near term.
The Company maintains insurance coverage intended to reimburse the cost of
damages and remediation related to environmental contamination resulting from
sudden and accidental incidents under current operations. The purchased
coverages contain specified and varying levels of deductibles and payment
limits. Although certain of the Company's contingent legal exposures enumerated
above are uninsurable due either 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.
-12-
Certain Litigation and Claims
City of Santa Monica MTBE Lawsuit: In June 2000, the City of Santa Monica (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 of water pumped from its Charnock wellfield (City of Santa Monica v
Shell Oil Company et al, California Superior Court, Orange County, Case No.
01CC04331). In August 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.
The City's first amended complaint, filed in May 2002, alleges causes of action
for strict liability (gasoline containing MTBE as a defective product designed,
manufactured and sold without adequate warnings), negligence, trespass, public
and private nuisance, declaratory relief and unfair competition. The City seeks
damages, a declaration that the defendants are liable for all remedial actions,
abatement of nuisance and injunctive relief. The City alleges that releases from
sites of units of Shell, ChevronTexaco Corporation and ExxonMobil Corporation
were the releases which caused the wellfield to be shut down. Releases from
Company sites allegedly impacted the wellfield subsequently.
In July 2002, the City, ChevronTexaco and ExxonMobil announced a proposed
settlement, under which the two companies would pay the City $30 million and
construct and operate a water treatment plant. Future settlement and/or judgment
amounts paid to the City from other defendants would go in part into an
operating account, from which the two companies could be reimbursed for part or
all of their treatment plant costs, as well as certain other costs. The Company,
Tosco Corporation (now a unit of Phillips Petroleum Company) and other
defendants, but not the Shell defendants, have been invited to participate in
this settlement. The Company is evaluating its position with regard to
participation, which would involve its paying the City $7.5 million and
contributing to the costs of the treatment plant. However, 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
liabilities arising from its former gasoline marketing business that was sold to
Tosco in 1997. The Company's current analysis does not indicate any such
liabilities are likely to be significant.
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. The
impact of the proposed settlement in the City's lawsuit on future government
agency actions is uncertain. 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 a U. S. subsidiary in the California
Superior Court, Los Angeles County (Agrium U.S. Inc. and Agrium Inc. v. Union
Oil Company of California, Case No. BC275407). The Company subsequently removed
the case to the U.S. District Court for the Central District of California (Case
No. 02-04769 Nm).
The Agrium entities ("Agrium") allege numerous causes of action relating to
their 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 a Gas
Purchase and Sale Agreement (the "GPSA") between the parties. Agrium alleges
that the Company misrepresented the amount of gas reserves available for sale to
the plant as of the closing of the transaction and that the Company has failed
to develop additional reserves for sale to the plant. Agrium also alleges that
-13-
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.
Also in June 2002, the Company filed a lawsuit against Agrium in the U.S.
District Court for the Central District of California (Union Oil Company of
California v. Agrium Inc. and Agrium U.S. Inc., Case No. 02-04518 Nm(Ctx)). 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 $16.6
million, together with interest accrued subsequent to May 31, 2002.
The Company believes that certain portions of its disputes with Agrium are
subject to binding arbitration under the terms of the GPSA, and has initiated
arbitration respecting the gas supply available under that agreement. Agrium
claims the dispute resolution provisions of the agreement for the sale of the
plant (the "PSA") supersede the arbitration provisions of the GPSA. Agrium has
filed motions to stay the Company's lawsuit, to enjoin implementation of the
arbitration and for Agrium's lawsuit to be remanded to the state court. A
hearing on these motions is set for September 2002. The federal court recently
denied a motion by Agrium to temporarily restrain implementation of the
arbitration.
The GPSA contains a contractual limit on liquidated damages of $25 million per
year, not to exceed a total of $50 million over the life of the agreement. In
addition, the PSA contains a limit on damages of $50 million. The Company
believes it has a meritorious defense to each of the Agrium claims, but that in
any event its exposure to damages for all disputes is limited by the agreements.
Agrium alleges that it is entitled to recover damages in excess of those
amounts.
Petrobangla Claim: In July 2002, the Company's subsidiary Unocal Bangladesh
Blocks Thirteen and Fourteen, Ltd. (which was acquired in 1999 from Occidental
Petroleum Corporation and, prior to the recent completion of Bangladesh
name-change formalities, was still known in Bangladesh as Occidental of
Bangladesh Ltd.) ("OBL"), received from the Bangladesh Oil, Gas & Mineral
Corporation ("Petrobangla") a letter 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 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 OBL has advised
Petrobangla that no additional compensation is warranted.
-14-
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.
Pure Resources, Inc. Employment and Severance Agreements
Under circumstances specified in the employment and/or severance agreements
entered into between the Company's Pure subsidiary and its officers, each
covered officer will have the right to require Pure to purchase its common
shares currently held or subsequently obtained by the exercise of any option
held by the officer at a calculated "net asset value" per share. The
circumstances under which certain officers may exercise this right include the
termination of the officer without cause prior to May 25, 2003, termination for
any reason after May 24, 2003, a change in control of either Pure or Unocal and
other events specified in the agreements. The net asset value per share is
calculated by reference to each common share's pro rata amount of the present
value of Pure's proved reserves discounted at 10 percent, as defined, times 110
percent, less funded debt, as defined. At June 30, 2002, Pure estimated that the
amount it may have to repurchase under these agreements was approximately $92
million, which is reflected as subsidiary stock subject to repurchase on the
consolidated balance sheet. The repurchase amount will fluctuate with changes in
the net asset value per share. At December 31, 2001, the repurchase amount under
these agreements was approximately $70 million.
-15-
Other matters
The Company has a lease agreement relating to its Discoverer Spirit deepwater
drillship, with a remaining term of approximately three years and three months
at June 30, 2002. In 2001, the Company signed a sublease agreement with a third
party for a minimum period of 200 days. The completion of the sublease period is
currently estimated to be in September 2002. Under the provisions of the
agreement, the third party assumed all of the lease payments to the lessor
during the sublease period, which began in December 2001. The drillship has a
minimum daily rate of approximately $219,000. The future remaining minimum lease
payment obligation, excluding the remaining sublease period, was approximately
$240 million at June 30, 2002.
In the normal course of business, the Company has performance obligations which
are secured 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 but are funded by the Company if
exercised. At June 30, 2002, the Company, including its Pure subsidiary, had
obtained various surety bonds for approximately $350 million. These surety bonds
primarily consisted of bonds for the Company's mining operation discussed in the
following paragraph and a bond for $99 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. The Company also had obtained
approximately $64 million in standby letters of credit at June 30, 2002. 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 $410 million. Approximately $200
million of the $410 million in guarantees would require the Company to obtain a
surety bond or a letter of credit, or establish a trust fund if its credit
rating drops below investment grade, that is BBB- or Baa3 from Standard & Poor's
Ratings Services and Moody's Investors Service, Inc., respectively.
Approximately $180 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.
As mentioned in the previous paragraph, the Company's Molycorp subsidiary has
permits covering discharges from its Questa, New Mexico, molybdenum mine.
Obtaining these permits involved the posting by Molycorp of two bonds totaling
$152 million that provide financial assurance of completion of temporary closure
plans (required only upon cessation of operations) and other obligations
required under the terms of the permits. These costs are based on estimations
provided by agencies of the state of New Mexico. Unocal has indemnified the
insurance company that issued the bonds with respect to all amounts that may be
drawn against them.
The Company has certain investments in entities that it accounts for under the
equity method, such as Colonial Pipeline Company. These entities have
approximately $1.8 billion of their own debt obligations that are either fully
non-recourse or of limited recourse to the Company. Of the total $1.8 billion in
equity investee debt, $1.1 billion belongs to the Colonial Pipeline Company, in
which the Company holds a 23.44 percent equity interest. The Company guarantees
only $27 million of the total $1.8 billion debt obligations.
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.
-16-
13. 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 June 30, 2002, including the current portion,
was approximately $3.31 billion. 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 the mandatorily redeemable convertible preferred
securities of the Company's subsidiary trust was approximately $527 million at
June 30, 2002. The fair value was based on the trading prices of the preferred
securities on June 28, 2002, as reported to the Company.
Commodity hedging activities - During the second quarter of 2002, the Company
recognized $1 million in after-tax losses for the ineffectiveness of both cash
flow and fair value hedges. For the six months ended June 30, 2002, the earnings
impact of ineffectiveness was immaterial. At June 30, 2002, the Company had
approximately $9 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 July 2002 through
October 2004. Of this amount, approximately $3 million in after-tax losses are
expected to be reclassified to the consolidated earnings statement during the
next twelve months.
Foreign currency contracts - At June 30, 2002, 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. Of this amount,
the losses expected to be reclassified to the consolidated earnings statement
during the next twelve months are immaterial.
Interest rate contracts - At June 30, 2002, the Company had approximately $3
million of after-tax deferred losses in accumulated other comprehensive income
on the consolidated balance sheet related to cash flow hedges of interest rate
exposure through September 2012. Of this amount, the losses expected to be
reclassified to the consolidated earnings statement during the next twelve
months are immaterial.
-17-
14. 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 CONSOLIDATING EARNINGS STATEMENT
For the three months ended June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 286 $ 1,298 $ (235) $ 1,349
Interest, dividends and miscellaneous income - 9 - 10 (11) 8
Gain (loss) on sales of assets - - 1 (2) - (1)
------------------------------------------------------------------------------------------------------------------
Total revenues - 9 287 1,306 (246) 1,356
Costs and other deductions
Purchases, operating and other expenses 1 - 259 836 (240) 856
Depreciation, depletion and amortization - - 93 162 - 255
Impairments - - 21 - - 21
Dry hole costs - - 2 11 - 13
Interest expense 9 1 35 9 (11) 43
Distributions on convertible preferred securities - 8 - - - 8
------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 9 410 1,018 (251) 1,196
Equity in earnings of subsidiaries 118 - 198 - (316) -
Earnings from equity investments - - 2 49 - 51
------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 108 - 77 337 (311) 211
------------------------------------------------------------------------------------------------------------------
Income taxes (3) - (41) 139 - 95
Minority interests - - - 1 2 3
------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 111 - 118 197 (313) 113
Earnings from discontinued operations - - - 1 - 1
------------------------------------------------------------------------------------------------------------------
Net earnings $ 111 $ - $ 118 $ 198 $ (313) $ 114
==================================================================================================================
-18-
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the three months ended June 30, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 487 $ 1,604 $ (407) $ 1,684
Interest, dividends and miscellaneous income - 9 4 8 (10) 11
Gain on sales of assets - - 1 - - 1
------------------------------------------------------------------------------------------------------------------
Total revenues - 9 492 1,612 (417) 1,696
Costs and other deductions
Purchases, operating and other expenses 1 - 272 1,112 (417) 968
Depreciation, depletion and amortization - - 91 154 - 245
Dry hole costs - - 24 23 - 47
Interest expense 9 1 40 8 (10) 48
Distributions on convertible preferred securities - 8 - - - 8
------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 10 9 427 1,297 (427) 1,316
Equity in earnings of subsidiaries 252 - 202 - (454) -
Earnings from equity investments - - 10 39 - 49
------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 242 - 277 354 (444) 429
------------------------------------------------------------------------------------------------------------------
Income taxes (4) - 37 147 - 180
Minority interests - - - 5 9 14
------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 246 - 240 202 (453) 235
Earnings from discontinued operations - - 12 - - 12
Cumulative effect of accounting change - - - - - -
------------------------------------------------------------------------------------------------------------------
Net earnings $ 246 $ - $ 252 $ 202 $ (453) $ 247
==================================================================================================================
-19-
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the six months ended June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 495 $ 2,279 $ (401) $ 2,373
Interest, dividends and miscellaneous income - 17 7 15 (19) 20
Gain (loss) on sales of assets - - 14 (13) - 1
----------------------------------------------------------------------------------------------------------------------------
Total revenues - 17 516 2,281 (420) 2,394
Costs and other deductions
Purchases, operating and other expenses 3 - 486 1,470 (402) 1,557
Depreciation, depletion and amortization - - 180 299 - 479
Impairments - - 21 - - 21
Dry hole costs - - 17 24 - 41
Interest expense 17 1 78 18 (20) 94
Distributions on convertible preferred securities - 16 - - - 16
----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 20 17 782 1,811 (422) 2,208
Equity in earnings of subsidiaries 148 - 326 - (474) -
Earnings from equity investments - - 2 86 - 88
----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 128 - 62 556 (472) 274
----------------------------------------------------------------------------------------------------------------------------
Income taxes (7) - (86) 228 - 135
Minority interests - - - 3 1 4
----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 135 - 148 325 (473) 135
Earnings from discontinued operations - - - 1 - 1
Cumulative effect of accounting change - - - - - -
----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 135 $ - $ 148 $ 326 $ (473) $ 136
============================================================================================================================
-20-
CONDENSED CONSOLIDATING EARNINGS STATEMENT
For the six months ended June 30, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,180 $ 3,686 $ (976) $ 3,890
Interest, dividends and miscellaneous income 5 17 3 13 (19) 19
Gain on sales of assets - - 1 - - 1
----------------------------------------------------------------------------------------------------------------------------
Total revenues 5 17 1,184 3,699 (995) 3,910
Costs and other deductions
Purchases, operating and other expenses 2 - 667 2,734 (997) 2,406
Depreciation, depletion and amortization - - 177 291 - 468
Impairments - - - - - -
Dry hole costs - - 34 53 - 87
Interest expense 17 1 85 13 (19) 97
Distributions on convertible preferred securities - 16 - - - 16
----------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 19 17 963 3,091 (1,016) 3,074
Equity in earnings of subsidiaries 551 - 413 - (964) -
Earnings from equity investments - - 8 83 - 91
----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 537 - 642 691 (943) 927
----------------------------------------------------------------------------------------------------------------------------
Income taxes (5) - 106 269 - 370
Minority interests - - - 9 21 30
----------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 542 - 536 413 (964) 527
Earnings from discontinued operations - - 16 - - 16
Cumulative effect of accounting change - - (1) - - (1)
----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 542 $ - $ 551 $ 413 $ (964) $ 542
============================================================================================================================
-21-
CONDENSED CONSOLIDATING BALANCE SHEET
At June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 61 $ 99 $ - $ 161
Accounts and notes receivable - net 51 - 56 792 (62) 837
Inventories - - 9 102 - 111
Other current assets - - 130 31 - 161
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 52 - 256 1,024 (62) 1,270
Investments and long-term receivables - net 4,123 - 4,455 1,078 (8,170) 1,486
Properties - net - - 2,141 5,600 - 7,741
Other assets 3 541 456 2,130 (2,834) 296
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,178 $ 541 $ 7,308 $ 9,832 $ (11,066) $ 10,793
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 242 $ 637 $ (51) $ 828
Current portion of long-term debt and capital leases - - - 8 - 8
Other current liabilities 46 3 144 372 40 605
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 46 3 386 1,017 (11) 1,441
Long-term debt and capital leases - - 2,489 622 - 3,111
Deferred income taxes - - (20) 698 - 678
Accrued abandonment, restoration
and environmental liabilities - - 305 282 - 587
Other deferred credits and liabilities 541 - 376 2,695 (2,890) 722
Subsidiary stock subject to repurchase - - - 92 - 92
Minority interests - - - 313 117 430
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 3,591 16 3,772 4,113 (8,282) 3,210
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,178 $ 541 $ 7,308 $ 9,832 $ (11,066) $ 10,793
=============================================================================================================================
-22-
CONDENSED CONSOLIDATING BALANCE SHEET
At December 31, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ 62 $ 128 $ - $ 190
Accounts and notes receivable - net 51 - 154 693 (51) 847
Inventories - - 3 99 - 102
Other current assets - - 122 34 - 156
-----------------------------------------------------------------------------------------------------------------------------
Total current assets 51 - 341 954 (51) 1,295
Investments and long-term receivables - net 4,032 - 4,143 968 (7,738) 1,405
Properties - net - - 2,149 5,365 - 7,514
Other assets 3 541 214 2,403 (2,950) 211
-----------------------------------------------------------------------------------------------------------------------------
Total assets $4,086 $ 541 $ 6,847 $ 9,690 $ (10,739) $ 10,425
=============================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 278 $ 596 $ (51) $ 823
Current portion of long-term debt and capital leases - - - 9 - 9
Other current liabilities 42 3 145 400 - 590
-----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 42 3 423 1,005 (51) 1,422
Long-term debt and capital leases - - 2,181 716 - 2,897
Deferred income taxes - - (71) 698 - 627
Accrued abandonment, restoration
and environmental liabilities - - 293 297 - 590
Other deferred credits and liabilities 541 - 312 2,821 (2,950) 724
Subsidiary stock subject to repurchase - - - 70 - 70
Minority interests - - - 309 140 449
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent debentures - 522 - - - 522
Stockholders' equity 3,503 16 3,709 3,774 (7,878) 3,124
-----------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $4,086 $ 541 $ 6,847 $ 9,690 $ (10,739) $ 10,425
=============================================================================================================================
-23-
CONDENSED CONSOLIDATING CASH FLOWS
For the six months ended June 30, 2002
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 80 $ - $ (110) $ 656 $ - $ 626
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (213) (617) - (830)
Proceeds from sales of assets
and discontinued operations - - 15 32 - 47
-------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (198) (585) - (783)
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 307 (96) - 211
Dividends paid on common stock (98) - - - - (98)
Other 19 - - (4) - 15
-------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (79) - 307 (100) - 128
-------------------------------------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents 1 - (1) (29) - (29)
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period - - 62 128 - 190
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1 $ - $ 61 $ 99 $ - $ 161
=========================================================================================================================
CONDENSED CONSOLIDATING CASH FLOWS
For the six months ended June 30, 2001
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 83 $ - $ 572 $ 589 $ - $ 1,244
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (373) (868) - (1,241)
Proceeds from sales of assets
and discontinued operations - - 28 2 - 30
-------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (345) (866) - (1,211)
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (5) 371 - 366
Dividends paid on common stock (97) - - - - (97)
Other 13 - - (10) - 3
-------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (84) - (5) 361 - 272
-------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents (1) - 222 84 - 305
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period 1 - 84 150 - 235
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ - $ - $ 306 $ 234 $ - $ 540
=========================================================================================================================
-24-
15. 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 those 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 June 30, 2002
Millions of dollars Lower 48 Alaska Canada Far East Other
------------------------------------------------------------------------------
Sales & operating revenues $ 124 $ 73 $ 61 $ 275 $ 37 $ 644
Other income (loss) (a) 1 - - - - -
Inter-segment revenues 234 - - 62 21 1
------------------------------------------------------------------------------
Total 359 73 61 337 58 645
Earnings (loss) from equity investments 1 - - 9 2 1
Earnings (loss) from continuing operations 20 (5) 6 113 12 1
Earnings from discontinued operations - - - - - -
------------------------------------------------------------------------------
Net earnings (loss) 20 (5) 6 113 12 1
Assets (at June 30, 2002) 3,255 352 1,125 2,718 804 178
------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Administrative Net Interest Environmental
& General Expense & Litigation Other (b)
-------------------------------------------------------------------------------------------
Sales & operating revenues $ 76 $ 33 $ - $ - $ - $ 26 $ 1,349
Other income (loss) (a) 1 2 - 5 - (2) 7
Inter-segment revenues 4 - - - - (322) -
-------------------------------------------------------------------------------------------
Total 81 35 - 5 - (298) 1,356
Earnings (loss) from equity investments 18 5 - - - 15 51
-
Earnings (loss) from continuing operations 23 14 (19) (28) (13) (11) 113
Earnings from discontinued operations - - - - - 1 1
-------------------------------------------------------------------------------------------
Net earnings (loss) 23 14 (19) (28) (13) (10) 114
Assets (at June 30, 2002) 506 595 - - - 1,260 10,793
-------------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-25-
--------------------------------------------------------------------------
Segment Information Exploration & Production Trade
For the Three Months North America International
ended June 30, 2001
Millions of dollars Lower 48 Alaska Canada Far East Other
--------------------------------------------------------------------------
Sales & operating revenues $ 167 $ 63 $ 97 $ 269 $ 39 $ 925
Other income (loss) (a) - - 2 (3) - 6
Inter-segment revenues 406 - - 55 26 1
--------------------------------------------------------------------------
Total 573 63 99 321 65 932
Earnings from equity investments 8 - - 8 - -
Earnings (loss) from continuing operations 142 13 14 113 5 4
Earnings from discontinued operations - - - - - -
Cumulative effect of accounting change - - - - - -
--------------------------------------------------------------------------
Net earnings (loss) 142 13 14 113 5 4
Assets (at December 31, 2001) 3,345 344 1,015 2,463 741 156
--------------------------------------------------------------------------
---------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Administrative Net Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------
Sales & operating revenues $ 39 $ 45 $ - $ - $ - $ 40 $ 1,684
Other income (loss) (a) 1 4 - 7 - (5) 12
Inter-segment revenues 2 - - - - (490) -
---------------------------------------------------------------------------------------
Total 42 49 - 7 - (455) 1,696
Earnings from equity investments 19 - - - - 14 49
Earnings (loss) from continuing operations 18 2 (21) (32) (16) (7) 235
Earnings from discontinued operations - - - - - 12 12
Cumulative effect of accounting change - - - - - - -
---------------------------------------------------------------------------------------
Net earnings (loss) 18 2 (21) (32) (16) 5 247
Assets (at December 31, 2001) 479 594 - - - 1,288 10,425
---------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-26-
----------------------------------------------------------------------------
Segment Information Exploration & Production Trade
For the Six Months North America International
ended June 30 2002
Millions of dollars Lower 48 Alaska Canada Far East Other
----------------------------------------------------------------------------
Sales & operating revenues $ 237 $ 124 $ 100 $ 494 $ 60 $ 1,100
Other income (loss) (a) 4 - - - - -
Inter-segment revenues 400 - - 114 41 1
----------------------------------------------------------------------------
Total 641 124 100 608 101 1,101
Earnings (loss) from equity investments - - - 17 4 -
Earnings (loss) from continuing operations 24 (11) (3) 203 24 2
Earnings from discontinued operations - - - - - -
----------------------------------------------------------------------------
Net earnings (loss) 24 (11) (3) 203 24 2
Assets (at June 30, 2002) 3,255 352 1,125 2,718 804 178
----------------------------------------------------------------------------
-----------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Administrative Net Interest Environmental
& General Expense & Litigation Other (b)
-----------------------------------------------------------------------------------------
Sales & operating revenues $ 139 $ 61 $ - $ - $ - $ 58 $ 2,373
Other income (loss) (a) 2 4 - 8 - 3 21
Inter-segment revenues 6 - - - - (562) -
-----------------------------------------------------------------------------------------
Total 147 65 - 8 - (501) 2,394
Earnings (loss) from equity investments 37 2 - - - 28 88
Earnings (loss) from continuing operations 42 20 (43) (65) (36) (22) 135
Earnings from discontinued operations - - - - - 1 1
-----------------------------------------------------------------------------------------
Net earnings (loss) 42 20 (43) (65) (36) (21) 136
Assets (at June 30, 2002) 506 595 - - - 1,260 10,793
-----------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
-27-
-------------------------------------------------------------------------
Segment Information Exploration & Production Trade
For the Six Months North America International
ended June 30, 2001
Millions of dollars Lower 48 Alaska Canada Far East Other
-------------------------------------------------------------------------
Sales & operating revenues $ 328 $ 135 $ 129 $ 501 $ 74 $ 2,428
Other income (loss) (a) 1 - 1 (6) (1) (1)
Inter-segment revenues 972 - - 110 61 1
-------------------------------------------------------------------------
Total 1,301 135 130 605 134 2,428
Earnings from equity investments 14 - - 19 - -
Earnings (loss) from continuing operations 383 32 11 219 27 7
Earnings from discontinued operations - - - - - -
Cumulative effect of accounting change - - - - - -
-------------------------------------------------------------------------
Net earnings (loss) 383 32 11 219 27 7
Assets (at December 31, 2001) 3,345 344 1,015 2,463 741 156
-------------------------------------------------------------------------
--------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power
Operations Administrative Net Interest Environmental
& General Expens & Litigation Other (b)
--------------------------------------------------------------------------------------
Sales & operating revenues $ 139 $ 89 $ - $ - $ - $ 67 $ 3,890
Other income (loss) (a) 2 7 - 13 - 4 20
Inter-segment revenues 4 - - - - (1,148) -
--------------------------------------------------------------------------------------
Total 145 96 - 13 - (1,077) 3,910
Earnings from equity investments 28 - - - - 30 91
Earnings (loss) from continuing operations 27 3 (44) (65) (50) (23) 527
Earnings from discontinued operations - - - - - 16 16
Cumulative effect of accounting change - - - - - (1) (1)
--------------------------------------------------------------------------------------
Net earnings (loss) 27 3 (44) (65) (50) (8) 542
Assets (at December 31, 2001) 479 594 - - - 1,288 10,425
--------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets.
(b) Includes eliminations and consolidation adjustments.
16. Subsequent Event
In July 2002, the Company's Unocal Geothermal of Indonesia, Ltd. ("UGI")
subsidiary and Dayabumi Salak Pratama, Ltd. ("DSPL"), a 50-percent equity
investee of UGI, reached agreement over pricing and production issues at its
Gunung Salak geothermal project in Indonesia with PT. PLN (Persero) ("PLN"), the
Indonesian state-owned electricity company, and Pertamina, the Indonesian
state-owned oil and natural gas company. The new agreement extends the primary
terms of the Joint Operation Contract and Energy Sales Contract ("ESC") to 2040
and also contains provisions to extend the deadline for transferring to PLN
generating plants currently operated by DSPL plus any additional plants
subsequently developed and operated by DSPL or the Company to the expiration
date of the ESC. The new agreement lowers the selling price of electricity
delivered by DSPL from 8.49 cents per kilowatt-hour (kWh) to 4.45 cents per kWh
and steam supplied to PLN by UGI from 4.25 cents per kWh to 3.75 cents per kWh.
Under the terms of the amended ESC both the selling price for electricity and
the selling price for geothermal steam are indexed for changes in foreign
exchange rates and inflation. The new agreement also provides for payment by PLN
of a portion of the past due receivable balances to the Company while the
Company foregoes a portion of the receivables.
-28-
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 the Unocal's 2001 Annual
Report on Form 10-K.
CONSOLIDATED RESULTS
For the Three Months For the Six Months
Ended June 30, Ended June 30,
-----------------------------------------------
Millions of dollars 2002 2001 2002 2001
------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations $ 113 $ 235 $ 135 $ 527
Earnings from discontinued operations 1 12 1 16
Cumulative effect of accounting change - - - (1)
------------------------------------------------------------------------------------------------------------------------
Net earnings $ 114 $ 247 $ 136 $ 542
========================================================================================================================
Continuing Operations
Second Quarter Results: Earnings from continuing operations were $113 million in
the second quarter of 2002 compared to $235 million for the same period a year
ago. The decrease was primarily due to lower natural gas production and lower
prices for natural gas and liquids. The second quarter of 2002 was impacted by
lower production compared with the same period a year ago, principally in the
Lower 48 operations, which reflected lower Gulf of Mexico natural gas production
stemming from a decline in Ship Shoal Block 295 ("Muni field") production(10
MMcf/d, net of royalty, in the second quarter of 2002 versus 126 MMcf/d, net of
royalty, in the second quarter of 2001) and reduced second-half 2001 drilling
activity, compared to the first half of 2001, in response to lower commodity
prices. Worldwide net daily production in the second quarter of 2002 averaged
486,000 BOE per day compared with 516,000 BOE per day a year ago. The lower
worldwide production reduced net earnings by approximately $70 million.
Lower natural gas prices reduced net earnings by approximately $25 million,
while lower liquids prices reduced net earnings by approximately $15 million.
The Company's worldwide average natural gas price, which was not impacted by
hedging activities, was $2.80 per Mcf in the second quarter of 2002, which was a
decrease of 61 cents per Mcf, or 18 percent, from the same period a year ago.
The Company's second quarter of 2001 included a loss of one cent per Mcf from
hedging activities. In the second quarter of 2002, the Company's worldwide
average liquids price was $22.63 per Bbl, which was a decrease of $1.70 per Bbl,
or 7 percent, from the same period a year ago. The Company's hedging program had
no impact on the average liquids price in the second quarter of 2002 while the
second quarter of 2001 included a loss of 5 cents per Bbl from hedging
activities.
The second quarter of 2002 was also negatively impacted by a $12 million
after-tax impairment in Alaska and a $12 million after-tax restructuring
provision for the Gulf Region business unit, which is part of the U.S. Lower 48
operations of the Exploration and Production segment. After-tax provisions for
environmental and litigation matters were $13 million in the second quarter of
2002, compared with $14 million in the same period a year ago. The second
quarter of 2002 also included an after-tax gain of $4 million in mark-to-market
accruals and realized gains and losses for non-hedge commodity derivatives
recorded by the Company's Northrock Resources Ltd. ("Northrock") subsidiary,
compared to an after-tax gain of $21 million in the same period a year ago.
-29-
Six Months Results: Earnings from continuing operations were $135 million in the
first six months of 2002 compared to $527 million for the same period a year
ago. The decrease was primarily due to lower commodity prices and lower
worldwide production. Lower natural gas prices reduced net earnings by
approximately $155 million, while lower liquids prices reduced net earnings by
approximately $50 million. The Company's worldwide average natural gas price,
including a benefit of 6 cents per Mcf from hedging activities, was $2.61 per
Mcf for the first six months of 2002, which was a decrease of $1.28 per Mcf or
33 percent from the $3.89 per Mcf, including a loss of 3 cents per Mcf from
hedging activities, from the same period a year ago. In the first six months of
2002, the Company's worldwide average liquids price was $20.53 per Bbl,
including a benefit of 2 cents per Bbl from hedging activities, which was a
decrease of $3.92 per Bbl or 16 percent from the $24.45 per Bbl, including a
loss of 5 cents per Bbl from hedging activities, from the same period a year
ago.
The results in the first six months of 2002 were also impacted by lower
production compared with the same period a year ago, which reduced net earnings
by approximately $190 million. The impact was principally in the Lower 48
operations, which reflected lower Gulf of Mexico natural gas production stemming
from the decline in Muni field production(13 MMcf/d net of royalty in the first
six months of 2002 versus 91 MMcf/d net of royalty for the first six months of
2001) and the reduction in the second-half 2001 drilling activity. The first six
months of 2002 included $6 million after-tax in pension related expenses,
compared to a benefit of $5 million after-tax in the first six months of 2001.
The results in the first six months of 2002 included the $12 million after-tax
impairment in Alaska and the $12 million after-tax restructuring provision for
the Gulf Region business unit. After-tax provisions for environmental and
litigation matters were $34 million in the first six months of 2002, compared
with $45 million in the same period a year ago. The first six months of 2002
also included a $2 million after-tax gain from an insurance settlement reached
with insurers for the recovery of amounts previously paid out for environmental
pollution claims and related costs and a $2 million after-tax gain adjustment
related to a Lower 48 prior year asset sale. The first six months of 2001
included an after-tax gain of $4 million in mark-to-market accruals and realized
gains and losses for non-hedge commodity derivatives by the Company's Northrock
subsidiary, while the first six months of 2002 did not have any gains or losses.
Revenues: Total revenues from continuing operations in the second quarter of
2002 were $1.36 billion compared with $1.70 billion for the same period a year
ago. In the first six months of 2002, total revenues from continuing operations
were $2.39 billion compared with $3.91 billion for the same period a year ago.
The decreases, in both the quarter and six months amounts, primarily reflected
lower hydrocarbon commodity prices, lower domestic natural gas production and
reduced activity in the purchase and resale of third party crude oil barrels
intended to take advantage of market price differentials. During 2001,
management decided to decrease its outside crude oil purchases for resale due to
increased volatility in the oil markets.
Discontinued Operations
The second quarter of 2002 included a $1 million after-tax gain from
discontinued operations, related to a participation payment received from the
purchaser of the Company's former West Coast refining, marketing and
transportation assets covering price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline. The second quarter
of 2001 included a similar after-tax gain for $12 million. The total after-tax
gain in the first six months of 2001 from discontinued operations was $16
million.
Cumulative Effect of Accounting Change
In the first quarter of 2001, the Company recorded a one-time non-cash $1
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 No. 133, "Accounting for Derivative Instruments and Hedging
Activities".
-30-
Exploration and Production
The Company engages in oil and gas exploration, development and production
worldwide. The results of this segment are discussed under two geographical
breakdowns of North America and International:
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. The
U.S. Lower 48 also includes the consolidated results of Pure Resources, Inc.
("Pure"), which operates primarily in the Permian and San Juan Basins in west
Texas and New Mexico, the Gulf of Mexico region and offshore in the Gulf of
Mexico. A substantial portion of the crude oil and natural gas produced in the
U.S. Lower 48 operations, excluding that of Pure, is sold to the Company's Trade
business segment. The remainder of North America production, including the
production of Pure and Northrock in Canada, 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, including Pure, uses hydrocarbon
derivative financial instruments such as futures, swaps and options to hedge
portions of the Company's exposure to commodity price fluctuations.
Second Quarter Results: After-tax earnings were $21 million in the second
quarter of 2002 compared to $169 million for the same period a year ago, which
was a decrease of $148 million. The decrease was primarily due to lower natural
gas production and lower natural gas and liquids prices. Lower natural gas
production during the second quarter of 2002 compared to the same period a year
ago reduced after-tax earnings by approximately $55 million. North America
average net daily natural gas production was 935 MMcf/d in the second quarter of
2002 compared to 1,132 MMcf/d in the same period a year ago, which was a
decrease of 17 percent. Natural gas production in the Lower 48 was 766 MMcf/d in
the second quarter of 2002 compared to 954 MMcf/d in the same period a year ago.
This decline reflected lower natural gas production from the Gulf of Mexico
shelf area including production from the Muni field, which averaged 10 MMcf/d,
net of royalty, in the second quarter of 2002 compared to 126 MMcf/d, net of
royalty, during the second quarter of 2001. Lower natural gas prices reduced
after-tax earnings by approximately $45 million, while lower liquids prices
reduced after-tax earnings by approximately $5 million. The average natural gas
price for North America, including a gain of one cent per Mcf from hedging
activities, was $2.97 per Mcf in the second quarter of 2002 compared to $4.16
per Mcf in the same period a year ago, which included a loss of 3 cents per Mcf
from hedging activities. In the second quarter of 2002, the Company's North
America average liquids price, with no impact from hedging activities, was
$22.47 per Bbl compared to $23.45 per Bbl in the same period a year ago, which
included a loss of 9 cents per Bbl from hedging activities. The results in the
second quarter of 2002 were also negatively impacted by a $12 million after-tax
impairment in Alaska and a $12 million after-tax restructuring provision for the
Gulf Region business unit. In addition, the Company's Northrock subsidiary
recorded $4 million in after-tax gains related to accruals and realized gains
and losses for non-hedging commodity derivative positions during the second
quarter of 2002 compared to an after-tax gain of $21 million in the same period
a year ago.
Restructuring: In June 2002, the Company adopted a restructuring plan that
resulted in a $12 million after-tax restructuring charge. The restructuring
charge covers the costs of terminating approximately 200 employees in the
Company's Sugar Land, Texas office and field locations. All of the affected
employees have been terminated or had received termination notices as of June
30, 2002. The restructuring plan involves organizational changes to eliminate
unnecessary work processes in the Company's Gulf Region business unit, which is
part of the U.S. Lower 48 operations.
The restructuring charge was included in the results of the U.S. Lower 48
section of the Exploration & Production segment. Cash expenditures related to
the restructuring plan are expected to be approximately $9 million in the second
half of 2002 and $7 million in 2003. The Company expects the plan to reduce
future salaries and benefits by an estimated $20 million pre-tax annually.
-31-
Six Months Results: After-tax earnings were $10 million in the first six months
of 2002 compared to $426 million for the same period a year ago, which was a
decrease of $416 million. The decrease was primarily due to lower natural gas
and liquids prices and lower natural gas production. The average natural gas
price for North America, including a gain of 11 cents per Mcf from hedging
activities, was $2.66 per Mcf in the first six months of 2002 compared to $5.01
per Mcf in the same period a year ago, which included a loss of 6 cents per Mcf
from hedging activities. In the first six months of 2002, the Company's North
America average liquids price, including a benefit of 3 cents per Bbl from
hedging activities, was $19.88 per Bbl compared to $23.96 per Bbl in the same
period a year ago, which included a loss of 9 cents per Bbl from hedging
activities. The lower natural gas prices reduced after-tax earnings by
approximately $200 million, while the lower liquids prices reduced after-tax
earnings by approximately $40 million. Natural gas production in North America
was 934 MMcf/d in the first six months of 2002 compared to 1,138 MMcf/d in the
same period a year ago. This decline reflected primarily lower natural gas
production from the Gulf of Mexico shelf area including production from the Muni
field, which averaged 13 MMcf/d net of royalty in the first six months of 2002
compared to 91 MMcf/d net of royalty during the first six months of 2001. Lower
natural gas production during the first six months of 2002 compared to the same
period a year ago reduced after-tax earnings by approximately $130 million. The
results in the first six months of 2002 also included the $12 million after-tax
impairment in Alaska and the $12 million after-tax restructuring provision for
the Gulf Region business unit. The first six months of 2001 included an
after-tax gain of $4 million in mark-to-market accruals and realized gains and
losses for non-hedge commodity derivatives by the Company's Northrock
subsidiary, while the first six months of 2002 did not have any gains or losses.
Dry hole costs in the first six months of 2002 were lower by $18 million
after-tax than the same period a year ago, primarily due to lower drilling
activity in the Gulf of Mexico.
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 and development activities primarily in Asia, Latin America and West
Africa.
Second Quarter Results: After-tax earnings totaled $125 million in the second
quarter of 2002 compared to $118 million in the same period a year ago, which
was an increase of $7 million. The increase was primarily due to $8 million in
higher liquids sales volumes, $7 million in higher natural gas prices and $8
million in lower dry hole costs. These positive factors were partially offset by
$9 million in lower liquids prices and $8 million in higher tax expense due to
higher effective tax rates, primarily due to changes in the Thai baht/U.S.
dollar exchange rate. Liquids sales volumes increased primarily due to the
startup of oil production in Thailand. The average natural gas price for
International operations was $2.64 per Mcf in the second quarter of 2002, which
was an increase of 3 percent from the same period a year ago. Dry hole costs in
the second quarter of 2002 were lower primarily due to exploratory dry holes
recorded during the second quarter of 2001 in Brazil and Gabon. The average
liquids price for International operations was $22.84 per Bbl in the second
quarter of 2002, which was a decrease of $2.77 per Bbl, or 11 percent, from the
same period a year ago.
Six Months Results: After-tax earnings totaled $227 million in the first six
months of 2002 compared to $246 million in the same period a year ago, which was
a decrease of $19 million. The decrease was primarily due to $20 million in
lower liquids prices and $15 million in higher tax expense due to higher
effective tax rates, primarily due to changes in the Thai baht/U.S. dollar
exchange rate. The average liquids price for International operations was $21.43
per Bbl in the first six months of 2002, which was a decrease of $3.67 per Bbl,
or 15 percent, from the same period a year ago. These negative factors were
partially offset by $7 million in higher natural gas prices and $11 million in
lower dry hole costs. The average natural gas price for International operations
was $2.56 per Mcf in the first six months of 2002 compared with $2.54 per Mcf in
the same period a year ago. Dry hole costs for the six months of 2002 were lower
primarily due to the 2001 exploratory dry holes in Brazil and Gabon.
-32-
OPERATING HIGHLIGHTS
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------ ------------------
2002 2001 2002 2001
-----------------------------------------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
Lower 48 (a) (b) 54 59 55 57
Alaska 25 24 25 24
Canada 17 15 18 15
--------------------------------------------------------------------------------------------- ------------------
Total liquids 96 98 98 96
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 766 954 754 911
Alaska 77 93 89 115
Canada 92 85 91 112
--------------------------------------------------------------------------------------------- ------------------
Total natural gas 935 1,132 934 1,138
North America Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 23.48 $ 24.72 $ 20.92 $ 25.62
Alaska $ 20.86 $ 22.27 $ 18.03 $ 22.55
Canada $ 21.92 $ 20.84 $ 19.15 $ 20.65
Average $ 22.47 $ 23.54 $ 19.85 $ 24.05
Natural gas (per mcf)
Lower 48 $ 3.12 $ 4.62 $ 2.68 $ 5.73
Alaska $ 1.57 $ 1.20 $ 1.57 $ 1.20
Canada $ 2.90 $ 2.85 $ 2.53 $ 3.94
Average $ 2.96 $ 4.19 $ 2.55 $ 5.07
-----------------------------------------------------------------------------------------------------------------
North America Average Prices (including hedging activities) (c) (d)
Liquids (per barrel)
Lower 48 $ 23.47 $ 24.57 $ 20.97 $ 25.47
Alaska $ 20.86 $ 22.27 $ 18.03 $ 22.55
Canada $ 21.92 $ 20.84 $ 19.15 $ 20.65
Average $ 22.47 $ 23.45 $ 19.88 $ 23.96
Natural gas (per mcf)
Lower 48 $ 3.12 $ 4.62 $ 2.80 $ 5.69
Alaska $ 1.57 $ 1.20 $ 1.57 $ 1.20
Canada $ 2.97 $ 2.48 $ 2.62 $ 3.65
Average $ 2.97 $ 4.16 $ 2.66 $ 5.01
-----------------------------------------------------------------------------------------------------------------
(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 9 9 9 8
Natural gas 98 106 98 95
Barrels oil equivalent 25 26 25 24
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portion of hedges.
-33-
OPERATING HIGHLIGHTS (CONTINUED)
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------ ------------------
2002 2001 2002 2001
-----------------------------------------------------------------------------------------------------------------
International Net Daily Production (e)
Liquids (thousand barrels)
Far East 54 48 53 49
Other (a) 20 19 20 19
--------------------------------------------------------------------------------------------- ------------------
Total liquids 74 67 73 68
Natural gas - dry basis (million cubic feet)
Far East 883 908 852 851
Other (a) 79 69 78 63
--------------------------------------------------------------------------------------------- ------------------
Total natural gas 962 977 930 914
International Average Prices (f)
Liquids (per barrel)
Far East $ 22.50 $ 24.91 $ 20.95 $ 24.57
Other $ 23.91 $ 27.51 $ 23.03 $ 26.36
Average $ 22.84 $ 25.61 $ 21.43 $ 25.10
Natural gas (per mcf)
Far East $ 2.63 $ 2.54 $ 2.55 $ 2.51
Other $ 2.79 $ 2.92 $ 2.64 $ 2.90
Average $ 2.64 $ 2.56 $ 2.56 $ 2.54
-----------------------------------------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (b) (e)
Liquids (thousand barrels) 170 165 171 164
Natural gas - dry basis (million cubic feet) 1,897 2,109 1,864 2,052
Barrels oil equivalent (thousands) 486 516 482 506
Worldwide Average Prices (excluding hedging activities) (c) (d)
Liquids (per barrel) $ 22.63 $24.38 $ 20.51 $ 24.50
Natural gas (per mcf) $ 2.80 $ 3.42 $ 2.55 $ 3.92
Worldwide Average Prices (including hedging activities) (c) (d)
Liquids (per barrel) $ 22.63 $24.33 $ 20.53 $ 24.45
Natural gas (per mcf) $ 2.80 $ 3.41 $ 2.61 $ 3.89
-----------------------------------------------------------------------------------------------------------------
(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 9 9 9 8
Natural gas 98 106 98 95
Barrels oil equivalent 25 26 25 24
(c) Excludes Trade segment margins.
(d) Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portion of hedges.
(e) International production is presented utilizing the economic interest method.
(f) International did not have any hedging activities.
-34-
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
Company's Exploration and Production segment, excluding Pure, in order to manage
the Company's exposure 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 other unaffiliated oil and gas producing and trading
companies for resale. In addition, the segment trades hydrocarbon derivative
instruments to manage exposures to commodity price fluctuations for which hedge
accounting is not used and to exploit anticipated opportunities arising from
commodity price fluctuations. These general 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.
The segment also purchases limited amounts of physical commodity inventories for
energy trading purposes when arbitrage opportunities arise.
Second Quarter Results: After-tax earnings totaled $1 million in the second
quarter of 2002 compared to $4 million in the same period a year ago. The
decrease was primarily due to lower results related to domestic natural gas and
crude oil marketing activities.
Sales and operating revenues from the Trade business segment were $645 million
in the second quarter of 2002 compared to $925 million in the same period a year
ago, which was a decrease of $280 million. These revenues represented
approximately 48 percent and 55 percent of the Company's total sales and
operating revenues for the second quarters of 2002 and 2001, respectively. In
the second quarter of 2002, natural gas revenues declined by $160 million
primarily due to lower commodity prices and lower domestic production volumes.
Crude oil revenues declined by $115 million, primarily due to reduced activity
in the purchase and resale of third party barrels intended to take advantage of
marketing opportunities. During 2001, management decided to decrease its outside
crude oil purchases for resale due to increased volatility in the oil markets.
Six Months Results: After-tax earnings totaled $2 million in the first six
months of 2002 compared to $7 million in the same period a year ago. The
decrease was primarily due to lower results related to domestic natural gas
marketing activities.
Sales and operating revenues were $1,100 million in the first six months of 2002
compared to $2,428 million in the same period a year ago, which was a decrease
of $1,328 million. These revenues represented approximately 46 percent and 62
percent of the Company's total sales and operating revenues for the first six
months of 2002 and 2001, respectively. In the first six months of 2002, natural
gas revenues declined by $625 million primarily due to lower commodity prices
and lower domestic production volumes. Crude oil revenues declined by $640
million, primarily due to reduced activity in the purchase and resale of third
party barrels intended to take advantage of market price differentials. During
2001, management decided to decrease its outside crude oil purchases for resale
due to increased volatility in the oil markets.
MIDSTREAM
The Midstream segment is comprised of the Company's equity interests in
petroleum pipeline companies, wholly-owned pipeline systems throughout the U.S.,
and the Company's North America gas storage business.
Second Quarter Results: After-tax earnings totaled $23 million in the second
quarter of 2002 compared to $18 million in the same period a year ago. The
increase was due primarily to improved results in the gas storage business.
Six Months Results: After-tax earnings totaled $42 million in the first six
months of 2002 compared to $27 million in the same period a year ago. The
increase was due primarily to $4 million in improved throughput volumes from the
pipeline business and a $6 million asset write-down related to a Colonial
Pipeline Company investment that was recorded in the first six months of 2001.
In addition, after-tax earnings in the gas storage business in the first six
months of 2002 have improved by $5 million compared with the same period a year
ago.
-35-
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 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.
Second Quarter Results: After-tax earnings totaled $14 million in the second
quarter of 2002 compared to $2 million in the same period a year ago. The
improved results were primarily due to approximately $7 million after-tax in
lower receivable provisions related to geothermal operations in Indonesia and $4
million after-tax in improved equity earnings from the Company's investments in
non-geothermal power plants in Thailand.
Six Months Results: After-tax earnings totaled $20 million in the first six
months of 2002 compared to $3 million in the same period a year ago. The
improved results were primarily due to approximately $15 million after-tax in
lower receivable provisions related to geothermal operations in Indonesia.
Agreements Reached on Indonesia Geothermal Contracts: In July 2002, the
Company's Unocal Geothermal of Indonesia, Ltd. ("UGI"), subsidiary and Dayabumi
Salak Pratama, Ltd. ("DSPL"), a 50-percent equity investee of UGI, reached
agreement over pricing and production issues at its Gunung Salak geothermal
project in Indonesia with PT. PLN (Persero) ("PLN"), the Indonesian state-owned
electricity company, and Pertamina, the Indonesian state-owned oil and natural
gas company.
Gunung Salak is a 330-megawatt (nominal installed nameplate rating) geothermal
production and electricity generation project on the western side of the island
of Java. UGI operates the steam fields as a contractor to Pertamina and delivers
geothermal steam to PLN, which operates three electricity-generating plants at
Salak. UGI also delivers steam to DSPL for three generating plants that supply
electricity to PLN on behalf of Pertamina.
The new agreement extends the primary terms of the Joint Operation Contract and
Energy Sales Contract ("ESC") to 2040. The new agreement increases the Unit
Rated Capacities for the generating plants operated by DSPL by 32 megawatts
thereby increasing minimum take-or-pay amounts payable under the ESC and also
includes a commitment by PLN to accept as much steam and electricity as possible
over the take-or-pay quantities in order to meet increased demand. In addition,
the agreement reaffirms the Government of Indonesia guarantee of PLN's
obligations to UGI, DSPL, Pertamina and the project's lenders.
The new agreement lowers the selling price of electricity delivered by DSPL from
8.49 cents per kilowatt-hour (kWh) to 4.45 cents per kWh and steam supplied to
PLN by UGI from 4.25 cents per kWh to 3.75 cents per kWh. Under the terms of the
amended ESC both the selling price for electricity and the selling price for
geothermal steam are indexed for changes in foreign exchange rates and
inflation.
The new agreement also provides for payment by PLN of a portion of the past due
receivable balances to the Company while the Company foregoes a portion of the
receivables. As of June 30, 2002, the Company's Indonesian Geothermal business
unit had a gross receivable balance of approximately $455 million. In July 2002,
the Company received $51 million from PLN in payment of a portion of the past
due receivable balances. The Company will retain a receivable balance of $93
million plus interest and expects to collect in full this amount over a period
of approximately four years. The remaining part of the outstanding receivables
will be written-off against a previously established allowance for bad debts.
-36-
CORPORATE AND OTHER
Corporate and Other includes general corporate overhead, miscellaneous
operations (e.g., real estate activities, carbon and minerals) and other
corporate unallocated costs. Net interest expense represents interest expense,
net of interest income and capitalized interest.
Second Quarter Results: The after-tax earnings effect for the second quarter of
2002 was a loss of $71 million compared to a loss of $76 million in the same
period a year ago. Lower after-tax expenses for environmental and litigation
matters benefited the second quarter of 2002, with expenses of $13 million
after-tax compared to $16 million after-tax for the same period a year ago. The
second quarter of 2002 results included tax related benefit adjustments and
lower employee related compensation, which was offset by higher pension related
expenses.
Six Months Results: The after-tax earnings effect for the first six months of
2002 was a loss of $166 million compared to a loss of $182 million in the same
period a year ago. Lower after-tax provisions for environmental and litigation
matters benefited the first six months of 2002, with expenses of $36 million
after-tax compared to $50 million after-tax for the same period a year ago. The
first six months of 2002 also benefited from a $2 million after-tax gain from an
insurance settlement related reached with insurers for the recovery of amounts
previously paid out for environmental pollution claims and related costs. The
first six months results of 2001 included a $10 million pre-tax, or $7 million
after-tax, contribution to a charitable foundation, while the first six months
of 2002 included a similar contribution of $3 million pre-tax, or $2 million
after-tax. The 2002 earnings benefit from the lower contribution and the tax
related benefit adjustments were partially offset by higher pension related
expenses. The first six months of 2002 included $6 million after-tax in pension
related expenses, compared to a benefit of $5 million after-tax in the first six
months of 2001. Net interest expense remained unchanged in the first six months
of 2002, as higher interest expense from a premium on an early repayment of
long-term debt was offset by higher capitalized interest on development
projects.
FINANCIAL CONDITION
At At At
June 30, December 31, June 30,
----------------------------------------------------
Millions of dollars 2002 2001 2001
----------------------------------------------------------------------------------------------------------------
Current ratio 0.9:1 0.9:1 1.1:1
Total debt and capital leases $ 3,119 $ 2,906 $ 2,959
Trust convertible preferred securities 522 522 522
Stockholders' equity 3,210 3,124 3,155
----------------------------------------------------
Total capitalization $ 6,851 $ 6,552 $ 6,636
====================================================
Total debt/total capitalization 46% 44% 45%
Floating-rate debt/total debt 21% 8% 6%
----------------------------------------------------------------------------------------------------------------
Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $626 million in the first six months of
2002 compared to $1,244 million in the same period a year ago. This decrease
principally reflected the effects of lower worldwide average natural gas and
liquids prices. The decrease was partially offset by $155 million in lower
income tax payments, net of refunds, compared to the first six months of 2001
and $30 million from the sale of certain domestic trade receivables during the
first six months of 2002.
-37-
Pre-tax proceeds from asset sales, including those classified as discontinued
operations, were $47 million for the first six months of 2002. Proceeds of
approximately $27 million were from an asset sale by the Company's Pure
subsidiary of oil and gas producing properties in the U.S. The remaining $20
million of proceeds were from various other oil and gas asset sales and other
miscellaneous properties. Pre-tax proceeds from asset sales, including those
classified as discontinued operations, were $30 million for the first six months
of 2001. The proceeds included $12 million from the sale of certain oil and gas
properties, $11 million from the sale of miscellaneous assets and $7 million
related to a participation payment received from the purchaser of the Company's
former West Coast refining, marketing and transportation assets covering price
differences between California Air Resources Board Phase 2 gasoline and
conventional gasoline.
Capital expenditures in the first six months of 2002 were $830 million, compared
with $824 million in the same period a year ago. The higher capital expenditures
in 2002 were primarily due to higher development expenditures in Indonesia and
an acquisition in Canada, the aggregate of which was substantially offset by
lower Gulf of Mexico exploratory expenditures. The Canadian acquisition involved
the Company's Northrock subsidiary, which completed, in June 2002, a cash
acquisition of all the outstanding shares of common stock of Corsair Exploration
Inc. ("Corsair") for $1.98 per share, or approximately $29 million. This
acquisition was funded with cash on hand. Corsair is a Canadian exploration and
production company primarily engaged in activity in West Central Alberta,
Canada. The transaction was valued at approximately $36 million, which included
$7 million in assumed debt and working capital deficiency. The capital
expenditures amount for the first six months of 2001 excludes Pure's acquisition
of properties from International Paper Company for $267 million and Pure's cash
outlay of $150 million, as of June 30, 2001, for the acquisition Hallwood Energy
Corporation, which are included as part of the major acquisitions line on the
consolidated cash flows statement.
The Company has taken appropriate action to mitigate credit exposure to
counterparties whose creditworthiness has deteriorated since the beginning of
the year. Counterparty credit lines have been reduced substantially or rescinded
entirely where it has been determined that there is unwarranted credit exposure.
In other instances, credit assurances in the form of prepayments, letters of
credit or guarantees have been obtained to support the credit extension.
The Company's long-term debt, including the current portion, was $3.12 billion
at June 30, 2002, compared with $2.91 billion at year-end 2001. This increase
primarily reflected the commercial paper borrowings made by the Company to fund
scheduled maturing fixed-rate debt and for other general corporate purposes (see
note 10 for further detail on the Company's long-term debt).
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 their 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.
Based on current commodity prices and current development projects, the Company
does not expect cash generated from operating activities, asset sales and cash
on hand in 2002 to be sufficient to cover its operating and capital spending
requirements and to meet dividend payments. The Company has substantial
borrowing capacity to enable it to meet anticipated and unanticipated cash
requirements. The Company relies on the commercial paper market on an interim
basis, its accounts receivable securitization program and its revolving credit
facilities to cover short-term borrowing requirements. The Company decreased the
fund availability of its accounts receivable securitization program availability
to $125 million from $204 million in the second quarter of 2002. At June 30,
2002, the Company had sold $100 million of its domestic trade receivables under
this program. The Company also has in place a universal shelf registration
statement with an unutilized balance of approximately $739 million, which can be
issued as 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.
-38-
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+ / Baa1 credit rating by
Standard & Poor's and Moody's, respectively. In May 2002, Moody's changed its
rating outlook for the Company's long-term debt to negative from stable and
retained an outlook of stable for the Company's Prime-2 commercial paper rating.
As outlined in the tables on pages 40 and 41 of Management's Discussion and
Analysis in Item 7 of the Company's 2001 Annual Report on Form 10-K, the Company
continues to believe that it does not have a liquidity exposure in the event of
a credit rating downgrade. In the event that the Company's credit ratings fall
to a level that prohibits it from accessing the commercial paper markets, the
Company would still be able to access funds under its revolving credit
facilities.
ENVIRONMENTAL MATTERS
At June 30, 2002, the Company's reserves for environmental remediation
obligations totaled $231 million, of which $116 million was included in current
liabilities. During the six months ended June 30, 2002, cash payments of $55
million were applied against the reserve and $49 million in provisions were
added to the reserve balance. In the first quarter of 2002, provisions of $31
million were recorded primarily for service stations and distribution
facilities; the former Guadalupe oil field; and the McColl Superfund site. A
provision was recorded for revised cost estimates related to the anticipated
cleanup of the Company's former service stations and distribution facilities
throughout the United States. The reserves for these sites are included in the
"Former Company-operated Sites" environmental reserve category shown in the
table below. The first quarter provisions also included an additional accrual
for revised cost estimates for various remediation projects at the Company's
former Guadalupe oil field on the central California coast. The reserve for the
Guadalupe oil field is included in the "Inactive or Closed Company Facilities"
category. The Company also recorded a provision for its estimated remaining
share of oversight and monitoring costs related to the McColl Superfund site in
Fullerton, California. The provision was recorded as the result of a federal
appeals court overturning a 1998 court decision that held the federal government
responsible for cleanup of the site because of its role in encouraging oil
companies to produce gasoline during World War II.
In the second quarter of 2002, provisions of $18 million were recorded primarily
for a former oil field in Michigan and for a site in York, Pennsylvania. A
provision for the estimated cost to cleanup contaminated areas that have been
identified at a former oil field in Michigan was added to the reserve in the
second quarter. This reserve is included in the "Former Company-operated Sites"
category. In the second quarter, a provision was also recorded for revised
remediation cost estimates related to a shutdown facility in York, Pennsylvania.
The facility had been operated by the Company's Molycorp subsidiary. The reserve
for this site is included in the "Inactive or Closed Company Facilities"
category.
The Company also estimated as of June 30, 2002, that it possibly could incur
additional remediation costs aggregating approximately $245 million. The
Company's total environmental reserve and possible additional liability amounts
are grouped into the following four categories.
At June 30, 2002
----------------------------
Possible
Millions of dollars Reserves Additional
-------------------------------------------------------------------------------------------------
Superfund and similar sites $ 18 $ 11
Active company facilities 37 66
Company facilities sold with retained liabilities
and former company-operated sites 97 71
Inactive or closed company facilities 79 107
-------------------------------------------------------------------------------------------------
Total reserves $ 231 $ 255
=================================================================================================
Also see notes 11 and 12 to the consolidated financial statement in Item 1 of
this report for additional information on environmental related matters.
-39-
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 51
through 53 of Management's Discussion and Analysis in Item 7 of the Company's
2001 Annual Report on Form 10-K for a discussion of certain of such conditions
and events.
Volatile energy prices are expected to continue to impact financial results in
the year 2002. 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 and security and other factors.
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.
The Company estimates that its net worldwide daily production for 2002 will
average in the lower end of the range between 490,000 and 500,000 BOE. The
anticipated production increase through the remainder of 2002 reflects new
projects in the Far East and Gulf of Mexico. The Company forecasts its net
earnings per share to be between $1.60 and $1.80 in 2002. This forecast assumes
average NYMEX benchmark prices of $25.10 per Bbl of crude oil and $3.05 per
MMBtus for North America natural gas. These price assumptions are based on
year-to-date actual prices and the NYMEX strip for the remainder of the year.
Earnings are expected to change 16 cents per share for every $1 change in the
Company's average worldwide realized price for crude oil and 8 cents per share
for every 10-cent change in the Company's average realized North America natural
gas price. The full-year forecast also includes pre-tax dry hole costs of $110
to $125 million.
Exploration and Production - North America
U.S. Lower 48: In the Gulf of Mexico deep water, the Company is continuing its
appraisal of the Trident discovery and is planning to drill a second appraisal
well in late 2002. After completing the Trident second appraisal well, the
Company plans to commence drilling another deepwater prospect by the end of 2002
or early 2003. In addition, the Company is continuing its participation in the
development of the Mad Dog discovery.
The Company is continuing to focus its exploration effort on deeper prospects
with higher resource potential in the Gulf of Mexico shelf.
The Company anticipates selling some of its low margin properties in the Gulf
Region towards the end of 2002 or in early 2003.
Alaska: The Company continues its participation in the Ninilchik Exploration
Unit on Alaska's Kenai Peninsula, where it holds a 40 percent working interest
in the 25,000-acre Ninilchik Exploration Unit. Marathon Oil Corporation
("Marathon") is operator and holds the remaining interest. The Ninilchik
Exploration Unit is located about 35 miles south of Kenai, Alaska.
Canada: The Company's Northrock subsidiary will work on integrating the recently
acquired operations of Corsair, a Canadian exploration and production company
primarily engaged in activity in West Central Alberta, Canada.
-40-
Exploration and Production - International
Far East
Thailand: The Company's Unocal Thailand, Ltd. ("Unocal Thailand"), subsidiary
started natural gas production from the Phase II development in the northern
part of Pailin field in the B12/27 concession area in the Gulf of Thailand. The
minimum daily contract quantity of natural gas sales from the Phase II ("North
Pailin") facilities is 165 gross MMcf/d, raising the gross contracted natural
gas sales from the Pailin field to 330 MMcf/d under an agreement with PTT Public
Co., Ltd. ("PTT"), the partially privatized state petroleum company. The North
Pailin facilities have produced an average of 180 gross MMcf/d throughout the
month of July. In addition, the North Pailin facilities have produced an average
of 5,300 gross b/d of condensate throughout the month of July, raising total
condensate production from Pailin to more than 14,600 gross b/d. Unocal Thailand
is operator of the field and holds a 35 percent working interest (31 percent net
of royalty).
The Company began crude oil production in May 2002 from its Yala field in the
Gulf of Thailand. The Company began initial production of crude oil from the
neighboring Plamuk field in 2001. The Company expects production from the
Plamuk, Yala and Surat fields to reach 15 MBbl/d gross in 2002. The Company has
a 71 percent working interest in these fields (62 percent net of royalty).
Vietnam: In May 2002, the Company's Vietnam subsidiaries filed a declaration of
commercial discovery with PetroVietnam, the national oil company, for three
natural gas fields offshore southwest Vietnam. The declaration followed the
drilling of 10 successful exploration wells on Blocks B and 52/97, including
four wells that were drilled in 2001. The declaration is the first step toward
signing a gas sales agreement, which is required before any field development
can begin. As a result of the declaration, PetroVietnam may exercise its option
to convert its carried participating interests into paying working interests.
Should PetroVietnam opt to convert to normal working interests, the Company
would hold a 42 percent working interest in Block B and Block 48/95 and a 43
percent working interest in Block 52/97.
Indonesia: 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
plans to drill the Ranggas #6 delineation well in the third quarter of 2002.
Unocal Rapak is operator of the Rapak PSC area and holds an 80 percent working
interest. The Company is also evaluating early development options for the
condensate discovered at its deepwater Gendalo-Gandang discovery in the Ganal
PSC, offshore Indonesia. The Company is the operator of the Ganal PSC and holds
an 80 percent working interest.
The Company is continuing its development of the West Seno project. Gross
development costs for the first phase are expected to be approximately $460
million, with an additional $225 million for the second phase (Unocal's net
share is expected to be approximately $415 million and $200 million for phase 1
and 2, respectively). The Company and its co-venturer are currently working to
secure financing for a portion of the total costs through the Overseas Private
Investment Corporation ("OPIC"). The Company and its co-venturer expect to
complete financing arrangements with OPIC in 2002 for two loans. One loan is
$300 million for the first phase, and the other loan is $50 million for the
second phase.
Other International
Azerbaijan: The Azerbaijan International Operating Company ("AIOC") consortium
is working on the development of the "Phase 1" portion of the offshore oil
reserves in the Caspian Sea from the Azeri and Chirag fields. This phase of the
project will develop an estimated 1.5 billion barrels of proved crude oil
reserves. Phase 1 gross production is scheduled to commence in early 2005 and is
expected to peak at approximately 360 MBbl/d. The Company has committed up to
$310 million for its share of the costs to develop Phase 1.
The Company has approved the expenditure of $400 million representing its share
of the estimated Azeri-Chirag-Gunashli Production Sharing Agreement Phase 2
project expenditures over a five to six year period. Such expenditure is
subject to partner and government approval of the project which the Company
anticipates occurring in the third quarter of 2002.
-41-
Bangladesh: The Company continues to work with the government of Bangladesh and
Petrobangla, the state oil and gas company, to develop additional reserves and
export natural gas to markets in neighboring India. At June 30, 2002, the
Company's business unit in Bangladesh had a gross receivable balance of
approximately $31 million relating to invoices billed for natural gas and
condensate sales to Petrobangla. Approximately $27 million of the outstanding
balance represented past due amounts and accrued interest for invoices covering
December 2001 through May 2002. In July 2002, payments were received for natural
gas sales and condensate covering billings for December 2001 and January 2002.
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. See also Note 12 to the consolidated financial
statement in Item 1 of this report for information regarding a claim made by
Petrobangla in July 2002 against one of the Company's subsidiaries for
compensation with respect to a 1997 well blowout.
Brazil: The drilling of an exploratory well on the BM-ES-1 Block in the Espirito
Santo Basin began in July of 2002. The Company acquired a 25 percent
non-operating working interest in the Block earlier in 2002. Drilling in the
adjacent BM-ES-2 Block will wait on results from the BM-ES-1 Block and is
projected to commence in the first quarter of 2003 at the earliest. The Company,
as operator, holds a 40.5 percent working interest in the BM-ES-2 Block.
Midstream
Construction of the Keystone Gas Storage Project in West Texas continues and is
expected to be on-line by the end of third quarter of 2002. The project will
initially have storage capacity of 3 billion cubic feet. The Company holds a 100
percent interest in the project.
In early August, the Company, through its participation in the AIOC consortium,
signed the agreement approving engineering plans for the Baku-Tblisi-Ceyhan
("BTC") pipeline in Turkey. The pipeline project is planned to have a crude oil
capacity of 1 million b/d. Completion of the pipeline is excepted 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 eight shareholders in the BTC pipeline project. The
pipeline company anticipates financing up to 70 percent of the pipeline's cost.
In Alaska, the Company along with Marathon, through their interests in the Kenai
Kachemak Pipeline LLC, are developing a 33-mile natural gas pipeline that would
connect a future producing area in Ninilchik with the existing south central
Alaska pipeline system in Kenai. The cost of the pipeline is currently estimated
to be $25 million. The Company holds a 40 percent interest in the pipeline
company.
The Company anticipates the sale of certain interests in nonstrategic pipelines
in the U.S. by the end of 2002.
Corporate and Other
For the full-year 2002, pension costs related to the Company's U.S. based
employees are expected to increase by approximately $25 million after-tax
compared to the full-year 2001. Lower returns on plan assets and the use of a
lower discount rate to measure benefit-related liabilities are the principal
factors behind the increase in current year expense.
The Company's consulting actuaries have completed the January 1, 2002 actuarial
valuation calculations for the Unocal Qualified Retirement Plan ("Plan")
covering eligible employees on the U.S. payroll and have reviewed pension trust
investment results for the first six months of 2002. The fair value of the
pension trust investments at June 30, 2002 is still in excess of the Plan's
accumulated benefit obligation ("ABO"). The Company is closely monitoring the
performance of the Plan's investment advisors and the returns on plan assets. If
actual returns on plan assets were to continue to be negative for the balance of
the current year resulting in the fair value of the Plan's assets falling below
the ABO, the resulting shortfall would require a charge to accumulated other
comprehensive income on the Company's consolidated balance sheet with no impact
on earnings for 2002. Furthermore, continued negative returns on Plan assets
would result in increased pension expense in future years and could result in
the termination of the "contribution holiday" currently in effect for the Plan.
-42-
Reformulated Gasoline Patents
The Company's efforts to enforce its patents for reformulated gasolines
continue. In its lawsuit to collect additional infringement damages from five
California refiners, the court has requested additional information and
arguments with respect to the royalty rate to be applied for infringing volumes
produced subsequent to July 1996. In June 2002, the U.S. Patent and Trademark
Office ("PTO") initially rejected all of the claims of the Company's '126
patent, as it had done earlier with respect to the '393 patent, as part of the
reexamination process. In July, the PTO granted a second request for
reexamination of the '393 patent based on additional alleged "prior art". The
Company continues to expect the claims of these patents to be sustained
following the conclusion of their reexamination.
FUTURE ACCOUNTING CHANGES
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No 143, "Accounting for
Asset Retirement Obligations". It is effective for fiscal years beginning after
June 15, 2002, and it requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred, as a
capitalized cost of the long-lived asset and to depreciate it over the useful
life of the asset. The Company is currently in the process of evaluating the
impact that SFAS No. 143 will have on its financial position and results of
operations.
In June 2002, the FASB issued 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
and is effective for the Company on January 1, 2003. The Company is currently
reviewing the provisions of SFAS No. 146 to determine the impact that the
statement will have on its financial position and results of operations.
Other proposed accounting changes considered from time to time by the FASB, the
U.S. SEC, the American Institute of Certified Public Accountants and the United
States Congress could materially impact the Company's reported financial
position and results of operations.
-43-
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, counterparty liquidity 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 hydrocarbon 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
for 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 June 30, 2002. Assuming a ten percent decrease in the
Company's weighted average borrowing costs at June 30, 2002, the potential
increase in the fair value of the Company's debt obligations and associated
interest rate derivative instruments, including the Company's net interests in
the debt obligations and associated interest rate derivative instruments of its
subsidiaries, would have been approximately $111 million at June 30, 2002.
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 June 30,
2002, 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.
-44-
Assuming an adverse change of ten percent in foreign exchange rates at June 30,
2002, 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 $10 million at June 30, 2002.
Credit Risk - The Company has taken appropriate action to mitigate credit
exposure to counterparties whose creditworthiness has deteriorated since the
beginning of the year. Counterparty credit lines have been reduced substantially
or rescinded entirely where it has been determined that there is unwarranted
credit exposure. In other instances, credit assurances in the form of
prepayments, letters of credit or guarantees have been obtained to support the
credit extension.
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 historical data
and uses a three-day time interval with a 97.5 percent confidence level. The
model includes offsetting physical positions for 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 purposes other than hedging was approximately $2 million at
June 30, 2002. The value at risk related to hydrocarbon derivatives held for
hedging purposes was approximately $5 million at June 30, 2002.
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 June 30, 2002, along with the
fair values of those instruments.
-45-
Open Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value
2002 2003 2004 2005 2006-2009 Asset (Liability) (b)
------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 2,450,000 - - - - $ 787
Average price, per MMBtu $ 3.43
------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 4,915,500 7,498,000 7,241,000 7,218,000 21,677,000 $ 41,405
Average swap price, per MMBtu $ 2.46 $ 2.33 $ 2.33 $ 2.37 $ 2.47
Receive fixed price (c)
Volume (MMBtu) 13,190,875 131,508 95,438 - - $ (3,093)
Average swap price, per MMBtu $ 2.77 $ 1.97 $ 1.97
------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) - - - - - $ -
Average price received, per MMBtu
Average price paid, per MMBtu
------------------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) 34,255,000 5,636,010 202,500 - - $ 1,413
Average ceiling price, per MMBtu $ 4.08 $ 4.67 $ 4.94
Average floor price, per MMBtu $ 2.92 $ 3.64 $ 2.92
------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) 180,000 180,000 - - - $ 10
Average Call price $ 5.95 $ 6.35
Put Volume (MMBtu) (1,180,000) (180,000) $ (271)
Average Put Price $ 3.04 $ 3.25
------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (OTC)
Put Volume (MMBtu) 94,944 - - - - $ 86
Average Put Price $ 3.96
------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 427,000 - - - - $ 1,765
Average price, per Bbl $ 22.72
------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) 500,000 - - - - $ 18
Average price, per Bbl $ 22.90
Call Volume (Bbls) 350,000 - - - - $ 152
Average price, per Bbl $ 32.14
------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Calender Spread)
Put Volume (Bbls) 300,000 - - - - $ 11
Average price, per Bbl $ 0.22
Call Volume (Bbls) (400,000) - - - - $ (34)
Average price, per Bbl $ 0.14
------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Calender Spread) OTC
Put Volume (Bbls) 600,000 - - - - $ 66
Average price, per Bbl $ 0.10
Call Volume (Bbls) (200,000) - - - - $ 54
Average price, per Bbl $ 0.50
------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 19,500 - - - - $ 3
Average swap price, per Bbl $ 25.88
Receive fixed price
Volume (Bbls) 27,500 - - - - $ (188)
Average swap price, per Bbl $ 18.71
------------------------------------------------------------------------------------------------------------------------
Crude Oil Collars
Volume (Bbls) 88,421 156,802 77,778 - - $ (457)
Average ceiling price, per Bbl $ 27.15 $ 25.33 $ 24.87
Average floor price, per Bbl $ 20.61 $ 19.77 $ 18.77
------------------------------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $5,983 thousand net claims against counterparties with non-investment grade credit ratings.
(c) Includes $9,369 thousand in assumed liabilities which were capitalized as acquisition costs.
-46-
Open Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value
2002 2003 Asset (Liability) (b)
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) (370,000) - $ 416
Average price, per MMBtu $ 3.73
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 8,823,725 828,400 $ (13,912)
Average swap price, per MMBtu $ 3.35 $ 3.27
Receive fixed price
Volume (MMBtu) 8,967,500 - $ (472)
Average swap price, per MMBtu $ 3.36
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 2,725,000 - $ 426
Average price received, per MMBtu $ 2.92
Average price paid, per MMBtu $ 2.77
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) (2,250,000) - $ 227
Average Call price $ 3.53
Put Volume (MMBtu) (250,000) - $ (92)
Average Put Price $ 3.00
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Option (Over the Counter)
Call Volume (MMBtu) (4,833,050) (3,055,200) $ (4,637)
Average Call price $ 4.40 $ 2.55
Put Volume (MMBtu) (5,500,000) - $ 120
Average Put price $ 2.14
------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (c)
Put Volume (MMBtu) (12,310,000) (2,000,000) $ 421
Average Strike price $ 0.24 $ 0.60
------------------------------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) (441,000) - $ 750
Average price, per Bbl $ 27.11
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) - - $ (320)
Average price, per Bbl
Call Volumes (Bbls) 300,000 - $ (113)
Average price, per Bbl $ 26.92
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Option (Calender Spread)
Put Volume (Bbls) 200,000 - $ 0
Average price, per Bbl $ 0.15
------------------------------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 7,738,006 - $ 1,082
Average swap price, per Bbl $ 27.00
Receive fixed price
Volume (Bbls) 2,925,024 - $ (5,353)
Average swap price, per Bbl $ 23.36
------------------------------------------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $706 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).
-47-
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, 2001 ("2001 Form 10-K"), and
in Item 1 of Part II of Unocal's Quarterly Report on Form 10-Q for the quarterly
period ended March 31, 2002. There is incorporated by reference: the information
regarding environmental remediation reserves and possible additional remediation
costs in notes 11 and 12 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 12 to the consolidated financial statements. See
also the discussion under "Reformulated Gasoline Patents" in the Outlook section
of Management's Discussion and Analysis of recent developments in certain
proceedings in which the Company is seeking to enforce its patents for
cleaner-burning gasolines.
Information with respect to recent developments in certain previously reported
proceedings and with respect to certain additional 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 3 of Item 3 of the 2001 Form 10-K, in June 2002, the
court, ruling on various pending motions, dismissed all of the plaintiffs'
tort causes of action that were premised on alleged intentional or
negligent actions of the Company. In August 2002, the court orally denied
the Doe plantiffs' motion for class certification and set a February 2003
trial date. The remaining causes of action in both cases are all premised
on whether the Company should be held vicariously liable for the alleged
wrongful acts of the Myanmar military. Therefore, the Company views the
award of any punitive or exemplary damages against the Company to be
remote, as it is not claimed that the Company was a direct perpetrator of
any wrongful acts. With possible damages at trial limited to lost wages and
property appropriation claims of the individual plaintiffs, the Company
believes that the outcomes of these 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. In June 2002, the U.S. Environmental Protection Agency ("EPA") issued to
the Company an administrative complaint alleging 16 violations of the
Emergency Planning and Community Right-To-Know Act of 1986. The complaint,
which seeks civil penalties aggregating $385,000, alleges that the Company
failed to make timely and/or complete and accurate chemical release reports
to the EPA with regard to certain chemicals manufactured, processed or
otherwise used at its former Los Angeles refinery during 1996 and 1997.
-48-
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The 2002 Annual Meeting of Stockholders of Unocal was held on May 20, 2002. The
following actions were taken by the stockholders at the Annual Meeting, for
which proxies were solicited pursuant to Regulation 14 under the Securities
Exchange Act of 1934, as amended:
1. The three nominees proposed by the board of directors were elected as
directors by the following votes for three-year terms expiring at the
2005 Annual Meeting of Stockholders, or until their successors are duly
elected and qualified:
Name Votes For Votes Withheld
James W. Crownover 213,235,772 6,327,893
Timoth H. Ling 214,066,046 5,497,619
Donald B. Rice 214,593,616 4,970,049
2. A proposal to ratify the appointment of PricewaterhouseCoopers LLP as
Unocal's independent accountants for 2002 was passed by a vote of
213,626,825 for versus 4,941,605 against and 995,235 abstentions. There
were no broker non-votes.
3. A proposal to approve the amendments to the 1998 Management Incentive
Program was passed by a vote of 200,022,248 for versus 17,507,867
against and 2,033,549 abstentions. There were no broker non-votes.
4. A stockholder proposal to urge the Board of Directors to adopt,
implement and enforce a code of conduct based on the International
Labor Organization's Conventions on Workplace Human Rights failed to
pass, with a vote of 61,266,708 for versus 125,497,527 against and
8,731,434 abstentions. There were 24,067,996 broker non-votes.
5. A stockholder proposal to link compensation and bonus packages of
Unocal's executives to the Company's ethical and social performance
failed to pass, with a vote of 16,276,788 for versus 173,508,678
against and 5,710,203 abstentions. There were 24,067,996 broker
non-votes.
ITEM 5. OTHER INFORMATION.
Effective June 27, 2002, Charles R. Larson resigned from the Unocal Board of
Directors to pursue his candidacy for Lieutenant Governor in the State of
Maryland. His position is currently vacant.
-49-
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits: The Exhibit Index on page 46 of this report lists
the exhibits that are filed as part of this report.
(b) Reports on Form 8-K:
Filed during the second quarter of 2002:
(1) Current Report on Form 8-K, dated and filed April 8,
2002, for the purpose of reporting, under Item 5, the
Company's drilling results in Indonesia and a first
quarter 2002 provision for environmental remediation.
(2) Current Report on Form 8-K, dated and filed April 25,
2002, for the purpose of reporting, under Item 5, the
Company's first quarter 2002 earnings and related
information and the Company's 2002 earnings forecast.
(3) Current Report on Form 8-K, dated June 20, 2002, and
filed June 25, 2002, for the purpose of reporting,
under Item 5, the Company's restructuring of its Gulf
business unit.
Filed during the third quarter of 2002 to the date hereof:
(1) Current Report on Form 8-K, dated June 10, 2002, and
filed July 29, 2002, for the purpose of reporting,
under Item 5, the Company's second quarter 2002
earnings, the commencement of production from Phase II
of the Pailin field in Thailand, Agreements reached on
Indonesia Geothermal Contracts, Agrium Inc. Litigation,
a Bangladesh-related claim and the Company's 2002
earnings forecast.
(2) Current Report on Form 8-K, dated and filed August 2,
2002, for the purpose of reporting, under Item 5,
Amendment No. 2 to the Rights Agreement, dated as of
August 2, 2002, between Unocal Corporation and Mellon
Investor Services LLC.
================================================================================
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: August 12, 2002 By: /s/JOE D. CECIL
---------------------------------
Joe D. Cecil
Vice President and Comptroller
(Duly Authorized Officer
Principal Accounting Officer)
================================================================================
-50-
================================================================================
EXHIBIT INDEX
12.1 Statement regarding computation of ratio of earnings to fixed
charges of Unocal Corporation for the six months ended June 30, 2002
and 2001.
12.2 Statement regarding computation of ratio of earnings to fixed
charges of Union Oil Company of California for the six months ended
June 30, 2002 and 2001.
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Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.
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